Day: March 27, 2017

VANCOUVER — A First Nation on Vancouver Island has approved a proposed liquefied natural gas export facility on its traditional territories.

Leaders of the Huu-ay-aht First Nation and the CEO of Vancouver-based Steelhead LNG held a joint news conference in Vancouver on Monday to announce what Chief Robert Dennis said was the First Nation’s “official entry into the international business world.” 

Members of the small First Nation voted Saturday to approve development of the LNG facility at Sarita Bay, on the west coast of Vancouver Island.

“I feel it is going to be a very inviting opportunity for international investors to come to Canada and say, ‘Hey, there is certainty there and we would be willing to work there,'” Dennis said.

Steelhead CEO Nigel Kuzemko said the company has National Energy Board licences to export 24 million tonnes of LNG through the Sarita Bay facility every year, but he said discussions are ongoing about how they’ll get the natural gas from northeastern B.C. and Alberta to Vancouver Island.

Kuzemko said existing pipelines are favoured, and Steelhead has been in talks over the possibility of bringing gas across the Salish Sea from Washington state or piping it across southern B.C.

The company’s plans could even include building a new pipeline linking Vancouver Island and the B.C. mainland, but it is too early to discuss the costs of getting the LNG to market, he said. 

“The project size, the scope, the scale and the amount we have to spend to do that will obviously evolve over time. We just don’t have a number to give you,” Kuzemko said.

The company planned to make a final investment decision on Sarita Bay by 2019 or 2020, with first production targeted for 2024, he said.

Steelhead and the First Nation did not offer specifics about job creation but Huu-ay-aht leaders said the First Nation will benefit significantly, as would other workers.

“We are going to make sure that we extend as much of our energy to make sure Huu-ay-aht people are working and also to contribute to the employment sector of other Canadians and other B.C. people who are also working for us,” Dennis said.

Neither Steelhead nor the First Nation would discuss the financial aspects of the agreement.

However, Huu-ay-aht leaders said the First Nation would have an equity stake in the project that they would co-manage to ensure environmental oversight and also have a financial component commensurate with the size of the development.

John Jack, executive councillor with the Huu-ay-aht, said it’s time the First Nation took its place within Canada and British Columbia.

“This is an example of a First Nation working with business and working with the people of B.C. and Canada in order to create value that fits both of our interests.”

 

 

The Canadian Press

FOR: CANACOL ENERGY LTD.
TSX SYMBOL: CNE
BVC SYMBOL: CNEC
OTCQX SYMBOL: CNNEF

Date issue: March 27, 2017
Time in: 7:55 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 27, 2017) – Canacol Energy Ltd.
(“Canacol” or the “Corporation”) (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to
report its light, medium and heavy crude oil and conventional natural gas
reserves and deemed volumes for the fiscal year end December 31, 2016. The
Corporation engaged DeGolyer and MacNaughton Canada Limited (“DMCL”) to prepare
independent reserves evaluations for its two primary conventional natural gas
fields in Colombia and for its oil reserves in Colombia and deemed volumes in
Ecuador. The DMCL evaluated reserves and deemed volumes represent 92% of the
Corporation’s total reserves and deemed volumes on a Total Proved “1P” basis.

The Corporation’s conventional natural gas reserves are located in the Lower
Magdalena Valley basin, Colombia. Canacol’s light and medium crude oil reserves
are located in the Llanos and Middle Magdalena Valley basins, Colombia.
Additional deemed volumes of light and medium crude oil are developed in the
Oriente basin, Ecuador. Heavy crude oil reserves are located in the Caguan
basin, Colombia.

/T/

Canacol Energy Ltd. Gross Reserves and Deemed Volumes Summary

—————————————————————————-

Gross Reserves + Deemed Volumes
Proved Proved Proved
Developed Developed Undeveloped
Producing Non-Producing
Product Type (“PDP”) (“PDNP”) (“PUD”)
Conventional natural gas Bcf 236.0 1.0 45.2
Light and medium crude(3) MMbbl 1.0 2.0 2.0
Heavy crude MMbbl – 0.1 2.1
Total oil equivalent(4) MMBOE 42.4 2.3 12.0
Before tax NPV-10(5) MM US$ $ 693.0 $ 36.5 $ 170.0
After tax NPV-10(5) MM US$ $ 506.9 $ 27.9 $ 116.0
—————————————————————————-

Canacol Energy Ltd. Gross Reserves and Deemed Volumes Summary

—————————————————————————-

Gross Reserves + Deemed Volumes
Total Total Proved
Total Proved + Probable
Proved + Probable + Possible
Product Type (“1P”) (“2P”) (“3P”)
Conventional natural gas Bcf 282.3 411.0 503.2
Light and medium crude(3) MMbbl 5.1 7.5 9.3
Heavy crude MMbbl 2.1 5.0 8.4
Total oil equivalent(4) MMBOE 56.7 84.6 106.0
Before tax NPV-10(5) MM US$ $ 899.5 $ 1,330.8 $ 1,594.2
After tax NPV-10(5) MM US$ $ 650.7 $ 945.3 $ 1,128.9
—————————————————————————-

1. The numbers in this table may not add exactly due to rounding
2. All reserves and deemed volumes are represented at Canacol’s working

interest share before royalties
3. Light and medium crude volumes include working interest volumes and
deemed volumes
4. The term “BOE” means a barrel of oil equivalent on the basis of 5.7 Mcf
of natural gas to 1 barrel of oil (“bbl”) as per Colombian regulatory
practice
5. Net Present Value (NPV) are stated in thousands of USD and are
discounted at 10 percent

/T/

Highlights include:

/T/

— Proved Developed Producing “PDP” reserves and deemed volumes increased

by 49% since December 31, 2015, to total 42.4 million barrels of oil
equivalent (“MMBOE”) at December 31, 2016
— Total Proved + Probable “2P” reserves and deemed volumes totaled 84.6
MMBOE at December 31, 2016, with a before tax value discounted at 10% of
US$ 1.3 billion, representing CAD $ 8.79 per share
— Achieved 1P reserve replacement of 166% and 2P reserve replacement of
194% based on calendar 2016 gross reserve and deemed volume additions of
9.3 MMBOE (1P) and 11 MMBOE (2P)
— Achieved 2P finding and development costs (“F&D”) of US$ 4.71/BOE for
its gas assets and US$ 5.31/BOE as a corporate total for calendar 2016
— Achieved 2P F&D of US$ 2.52/BOE for its gas assets and US$ 3.48/BOE as a
corporate total for the 2 year period ending December 31, 2016
— Recorded 2P finding, development and acquisition costs (“FD&A”) of US$
5.04/BOE for its gas assets and US$ 5.66/BOE as a corporate total for
calendar 2016
— Recorded a 2P reserves life index (“RLI”) of 13 years based on
annualized fourth quarter 2016 production of 17,778 BOEpd

/T/

Ravi Sharma, Chief Operating Officer of Canacol Energy, commented: “The
Corporation has achieved significant conventional natural gas exploration and
development drilling success over the past 3.5 years. During this time, we have
added over 315 BCF of 2P conventional natural gas reserves from commercial
success on 11 out of 12 wells, representing a 52% compound annual growth rate
(“CAGR”). As of December 31, 2016, Canacol’s total 1P reserves and
corresponding before tax NPV-10 are 57 MMBOE and US$ 900 million, respectively,
or CAD $5.47 per share. The Corporation’s 2P reserves and corresponding before
tax NPV-10 are 85 MMBOE and US$ 1.3 billion, respectively, or CAD $8.79 per
share.

Canacol’s management team continues to execute its growth strategy with respect
to high value Colombian gas. The Corporation forecasts 130 million cubic feet
of gas per day (“MMcfd”) of natural gas production for exit rate 2017 and 230
MMcf/d of natural gas production for exit rate 2018. These targets represent
production growth of 44% from current production of 90 MMcf/d and sequential
production growth of 77% from 130 to 230 MMcf/d to exit 2018. ”

Discussion of Year Ended December 31, 2016 Reserves Report

During the six month period from June 30th 2016 to December 31st 2016, the
Corporation recorded increases in certain reserve categories as a result of the
drilling and completion of exploration locations at Nelson-6, Nispero-1 and
Trombon-1 on the Esperanza natural gas block in the Lower Magdalena valley
Basin, Colombia.

The following tables summarize information from the independent reserves report
prepared by DeGolyer and MacNaughton Canada Limited, effective December 31,
2016 (the “DMCL 2016 report”) and the independent reserves report prepared by
Petrotech Engineering Ltd., effective December 31, 2016 (the “Petrotech 2016
report”). The DMCL 2016 report covers 100% of the Corporation’s oil reserves
and deemed volumes and 90% of Canacol’s natural gas reserves on a 1P basis,
including Nelson and Clarinete fields.

Each independent reserves report was prepared in accordance with definitions,
standards and procedures contained in the Canadian Oil and Gas Evaluation
Handbook (“COGE Handbook”) and National Instrument NI 51-101, Standards of
Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve
information as required under NI 51-101 is included in the Corporation’s Annual
Information Form which will be filed on SEDAR by March 31, 2017.

/T/

Canacol Gross Reserves and Deemed Volumes for the Year Ended December 31,
2016

—————————————————————————-
Reserve Category(1) 31-Dec-15 31-Dec-16 Difference
(MBOE)(2) (MBOE) (%)
Proved Developed Producing 28,413 42,426 49%
Proved Developed Non-Producing 2,882 2,265 -21%
Proved Undeveloped 21,717 12,045 -45%
Total Proved (1P) 53,012 56,735 7%
Total Proved + Probable (2P) 79,229 84,570 7%
Total Proved + Probable + Possible (3P) 93,032 106,016 14%
—————————————————————————-

1. All reserves and deemed volumes are Canacol working interest before

royalties
2. MBOE is defined as thousands of barrels of oil equivalent. Gas volumes
are converted to BOE using a factor of 5.7mcf/BOE as per Colombia
regulatory practice

5-Year Crude Oil Price Forecast – DMCL Report December 31, 2016 vs. December
31, 2015

—————————————————————————-

Reserve
Report Date 2017 2018 2019 2020 2021
WTI US$/Bbl 31-Dec-16 55.00 59.16 63.46 68.98 72.52
WTI US$/Bbl 31-Dec-15 56.10 60.34 66.86 72.52 77.29
% difference -2% -2% -5% -5% -6%
—————————————————————————-

5-Year Gas Price Forecast – DMCL and Petrotech Reports December 31, 2016 vs.
Petrotech 2015

—————————————————————————-

Reserve
Report Date 2017 2018 2019 2020 2021
Volume weighted
average gas price US$/MMbtu 31-Dec-16 5.25 5.25 5.37 5.50 5.50
Volume weighted
average gas price US$/MMbtu 31-Dec-15 6.21 6.25 6.47 6.70 6.97
% difference -15% -16% -17% -18% -21%
—————————————————————————-

1. Gas price forecast is based on existing long term contracts adjusted for

inflation

Reserves and Deemed Volumes Net Present Value Before & After Tax Summary (1)

—————————————————————————-

Before tax After tax
———————— ————————
Net Asset Net Asset
Value Value
Reserve Category 31-Dec-16 31-Dec-16 31-Dec-16 31-Dec-16
($ ($
(M US$)(2) CAD/share)(2) (M US$)(2) CAD/share)(2)
————————————————– ————————
Proved Developed
Producing $ 692,992 $ 3.88 $ 506,871 $ 2.44
Proved Developed Non-
Producing $ 36,493 – $ 27,886 –
Proved Undeveloped $ 170,046 – $ 115,975 –
Total Proved (1P) $ 899,531 $ 5.47 $ 650,732 $ 3.55
Total Proved + Probable
(2P) $1,330,752 $ 8.79 $ 945,302 $ 5.82
Total Proved + Probable +
Possible (3P) $1,594,155 $ 10.82 $1,128,868 $ 7.23
—————————————————————————-

1. Net present values are stated in thousands of USD and are discounted at

10 percent. The forecast prices used in the calculation of the present
value of future net revenue are based on the price decks described
above. The DMCL price deck at December 31, 2016 is included in the
Corporation’s Annual Information Form. The DMCL and Petrotech forecasts
for gas prices at December 31, 2016 are included in the Corporation’s
Annual Information Form.
2. Net asset value (“NAV”) is calculated at December 31, 2016 NPV10 less
estimated net debt of US$190 million (being $255 million of bank debt
less estimated net working capital of $65 million) divided by 174
million basic shares outstanding as at December 31, 2016. NAV
calculations are converted to $CAD at USD:CAD = 1.3427.

Reserve Life Index (“RLI”)

—————————————————————————-
Reserve Category(1) 31-Dec-15 31-Dec-16
(yrs.)(1) (yrs.)(2)
Total Proved (1P) 16 9
Total Proved + Probable (2P) 24 13
—————————————————————————-

1. Calculated using average 3 month ending December 31, 2015 production of

9,064 BOEpd annualized. Production volumes include Ecuador incremental
production contract barrels.
2. Calculated using average 3 month ending December 31, 2016 production of
17,778 BOEpd annualized. Production volumes include Ecuador incremental
production contract barrels.
3. “RLI” Reserve Life Index is calculated by dividing a category of year
end reserves by expected current production rate.

Year Ended December 31, 2016 Canacol Gross Reserves Reconciliation (1)

—————————————————————————-

Light/Med
Total Oil Oil Heavy Oil
(MBBL) (MBBL) (MBBL)
TOTAL PROVED
—————————————————————————-
Opening Balance (December 31, 2015) 7,815 5,632 2,183
—————————————————————————-
Extensions – – –
Improved Recovery – – –
Technical Revisions(2) 701 746 (45)
Discoveries(3) – – –
Acquisitions – – –
Dispositions – – –
Economic Factors(4) (1) (1) –
Production (1,298) (1,290) (8)
—————————————————————————-
Closing Balance (December 31, 2016) 7,217 5,087 2,130
—————————————————————————-

Light/Med
Total Oil Oil Heavy Oil
(MBBL) (MBBL) (MBBL)
TOTAL PROVED + PROBABLE
—————————————————————————-
Opening Balance (December 31, 2015) 13,967 8,614 5,353
—————————————————————————-
Extensions – – –
Improved Recovery – – –
Technical Revisions(2) (205) 140 (345)
Discoveries(3) – – –
Acquisitions – – –
Dispositions – – –
Economic Factors(4) – – –
Production (1,298) (1,290) (8)
—————————————————————————-
Closing Balance (December 31, 2016) 12,464 7,464 5,000
—————————————————————————-

Year Ended December 31, 2016 Canacol Gross Reserves Reconciliation (1)

—————————————————————————

Sales Gas NGL TOTAL
(MMCF) (MBBL) MBOE
TOTAL PROVED
—————————————————————————
Opening Balance (December 31, 2015) 257,624 – 53,014
—————————————————————————
Extensions – – –
Improved Recovery – – –
Technical Revisions(2) 19,286 – 4,082
Discoveries(3) 30,027 – 5,268
Acquisitions – – –
Dispositions – – –
Economic Factors(4) – – (1)
Production (24,681) – (5,628)
—————————————————————————
Closing Balance (December 31, 2016) 282,256 – 56,735
—————————————————————————

Sales Gas NGL TOTAL
(MMCF) (MBBL) MBOE
TOTAL PROVED + PROBABLE
—————————————————————————
Opening Balance (December 31, 2015) 371,992 – 79,228
—————————————————————————
Extensions – – –
Improved Recovery – – –
Technical Revisions(2) (6,476) – (1,340)
Discoveries(3) 70,167 – 12,310
Acquisitions – – –
Dispositions – – –
Economic Factors(4) – – –
Production (24,681) – (5,628)
—————————————————————————
Closing Balance (December 31, 2016) 411,002 – 84,570
—————————————————————————

1. The numbers in this table may not add due to rounding
2. Technical revisions (conventional natural gas) are associated with the

Nelson and Clarinete gas fields, technical revisions (light/medium oil)
are associated with LLA23 and Ecuador assets, technical revisions (heavy
oil) are associated with the Ombu block
3. Discoveries are associated with the Oboe discovery on VIM-5 block and
Nispero, Trombon and Porquero discoveries on Esperanza block
4. Economic factors are related to price and royalty factor changes
5. Production volumes include Ecuador incremental production contract
barrels

Reserve Metrics Reconciliation – Canacol Working Interest before Royalty (1)
(2) (3)

—————————————————————————-

2 Year Ending
Calendar 2016 December 31, 2016
Conventional Conventional
Natural Gas Total(4) Natural Gas Total(4)
—————————————————————————-
Capital Expenditures $63,770 82,880 93,973 164,418
Capital Expenditures –
Change in FDC(5) (11,100) (27,600) 21,300 (22,700)
—————————————————————————-
Total F&D(6) $52,670 55,280 115,273 141,718
Net Acquisitions 3,665 3,665 41,711 41,711
—————————————————————————-
Total FD&A(7)(8) $56,335 58,945 156,984 183,429
—————————————————————————-
—————————————————————————-
Reserve Additions (MBOE) 11,174 10,407 45,768 40,742
Reserve Additions – Net
Acquisitions 0 0 6,580 6,445
—————————————————————————-
Reserve Additions Including
Net Acquisitions (MBOE) 11,174 10,407 52,348 47,187
—————————————————————————-
—————————————————————————-
F&D Costs ($/BOE)(6) $4.71 $5.31 $2.52 $3.48
FD&A Costs ($/BOE) (7)(8) $5.04 $5.66 $3.00 $3.89
—————————————————————————-

1. The numbers in this table may not add due to rounding
2. 2016 capital expenditure numbers exclude US $33 million related to the

Jobo 2 gas plant finance lease
3. All values in this table are stated on a 2P (Total Proved + Probable)
basis
4. Total oil and gas includes Colombian properties only. No Ecuador deemed
volumes nor capital have been included
5. “Capital Expenditures – change in FDC” is rounded to the nearest M US$.
FDC is the 2P (Proved + Probable) future development capital
6. F&D – Finding and Development Costs on a 2P (Total Proved + Probable)
basis
7. FD&A – Finding, Development and Acquisition Costs on a 2P (Total Proved
+ Probable) basis
8. With the finding and development costs, the aggregate of the exploration
and development costs incurred in the most recent financial year and the
change during that year in estimated future development costs generally
will not reflect total finding and development costs related to reserve
additions for that year.

/T/

The recovery and reserve estimates of light and medium crude oil, heavy crude
oil and conventional natural gas are estimates only. There is no guarantee that
the estimated reserves will be recovered and actual reserves of light and
medium crude oil, heavy crude oil and conventional natural gas may prove to be
greater than, or less than, the estimates provided.

Reserves of light and medium crude oil and heavy crude oil as at December 31,
2016 are evaluated against the DMCL forecast pricing effective at that date.
Comparative volumes of light and medium crude oil and heavy crude oil as at
December 31, 2015 are evaluated against the DMCL forecast pricing effective at
that date. Deemed volumes of light crude oil are determined by dividing cash
flow by the tariff price of USD$38.54/barrel which remains constant for the
life of the incremental production contract. Reserves of conventional natural
gas as at December 31, 2016 are evaluated against contract pricing forecast for
each gas contract. Comparative volumes of conventional natural gas as at
December 31, 2015 are evaluated against contract pricing for each gas contract
at the effective date. Forecast prices used in the reserves reports are
included in the Corporation’s Annual Information Form which will be filed on
SEDAR by March 31, 2017 under the sections “Forecast Prices Used in Estimates”
and “Forward Contracts” in the “Statement of Reserves Data and Other Oil and
Gas Information”.

All amounts in this news release are stated in Canadian dollars unless
otherwise specified.

Canacol is an exploration and production company with operations focused in
Colombia, Ecuador and Mexico. The Corporation’s common stock trades on the
Toronto Stock Exchange, the OTCQX in the United States of America, and the
Colombia Stock Exchange under ticker symbol CNE, CNNEF, and CNE.C, respectively.

Forward-Looking Information and Statements

This news release contains certain forward-looking information and statements
within the meaning of applicable securities law. Forward-looking statement are
frequently characterized by words such as “anticipate,” “continue,” “estimate,”
“expect”, “objective,” “ongoing,” “may,” “will,” “project,” “should,”
“believe,” “plan,” “intend,” “strategy,” and other similar words, or statements
that certain events or conditions “may” or “will” occur, including without
limitation statements relating to estimated production rates from the
Corporation’s properties and intended work programs and associated timelines.

Forward-looking statements are based on the opinions and estimates of
management at the date the statements are made and are subject to a variety of
risks and uncertainties and other factors that could cause actual events or
results to differ materially from those projected in the forward-looking
statements. The Corporation cannot assure that actual results will be
consistent with these forward looking statements. They are made as of the date
hereof and are subject to change and the Corporation assumes no obligation to
revise or update them to reflect new circumstances, except as required by law.
Prospective investors should not place undue reliance on forward looking
statements. These factors include the inherent risks involved in the
exploration for and development of crude oil and natural gas properties, the
uncertainties involved in interpreting drilling results and other geological
and geophysical data, fluctuating energy prices, the possibility of cost
overruns or unanticipated costs or delays and other uncertainties associated
with the oil and gas industry. Other risk factors could include risks
associated with negotiating with foreign governments as well as country risk
associated with conducting international activities, and other factors, many of
which are beyond the control of the Corporation.

The reserves evaluations, effective December 31, 2016, were conducted by the
Corporation’s independent reserves evaluators DeGolyer and MacNaughton Canada
Limited (“DMCL”) and Petrotech Engineering Ltd. (“Petrotech”) and are in
accordance with National Instrument 51-101 – Standards of Disclosure for Oil
and Gas Activities. The reserves are provided on a Canacol Gross basis in units
of barrels of oil equivalent using a forecast price deck, adjusted for quality,
in US dollars. The estimated values may or may not represent the fair market
value of the reserve estimates.

“Gross” in relation to the Corporation’s interest in production or reserves is
its working interest (operating or non-operating) share before deduction of
royalties and without including any royalty interests of the Corporation;

“Net” in relation to the Corporation’s interest in production or reserves is
its working interest (operating or non-operating) share after deduction of
royalty obligations, plus its royalty interest in production or reserves;

“Proved reserves” are those reserves that can be estimated with a high degree
of certainty to be recoverable. It is likely that the actual remaining
quantities recovered will exceed the estimated proved reserves;

“Probable reserves” are those additional reserves that are less certain to be
recovered than proved reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated
proved plus probable reserves;

“Possible reserves” means those additional reserves that are less certain to be
recovered than probable reserves. It is unlikely that the actual remaining
quantities recovered will exceed the sum of the estimated proved plus probable
plus possible reserves;

“Deemed Volumes” refer to Volume 3 of COGEH, Reserves Recognition for
International Properties, Section 4 – Fiscal Regime, Service Contracts, and
refer to those volumes produced under a risked Service Agreement in which the
Corporation does not have a direct interest, but represents reserves
attributable to the Corporation. By definition, these volumes are calculated as
the production revenue divided by the fixed tariff price or operating netback
per barrel, and are considered additive to volumes certified as reserves. Under
the terms of this risked Service Agreement, these calculated volumes correspond
to actual volumes produced. The Corporation has a non-operated 25% equity
participation interest in the Ecuador IPC for which it receives a fixed price
tariff for each incremental barrel produced.

BOE Conversion – “BOE” barrel of oil equivalent is derived by converting
natural gas to oil in the ratio of 5.7 Mcf of natural gas to one bbl of oil. A
BOE conversion ratio of 5.7 Mcf to 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead. As the value ratio between natural gas and
crude oil based on the current prices of natural gas and crude oil is
significantly different from the energy equivalency of 5.7:1, utilizing a
conversion on a 5.7:1 basis may be misleading as an indication of value. In
this news release, the Corporation has expressed BOE using the Colombian
conversion standard of 5.7 Mcf: 1 bbl required by the Ministry of Mines and
Energy of Colombia.

“1P” means Total Proved

“2P” means Total Proved + Probable

“3P” means Total Proved + Probable + Possible

1P Reserves replacement ratio: Ratio of reserve additions to production, as
reported in financial statements during the fiscal year ended December 31,
excluding acquisitions and dispositions on a Total Proved basis.

2P Reserves replacement ratio: Ratio of reserve additions to production, as
reported in financial statements during the fiscal year ended December 31,
excluding acquisitions and dispositions on a Total Proved + Probable basis.

2P Finding and development costs per barrel of oil equivalent (BOE) represent
exploration and development costs incurred per BOE of Total Proved + Probable
reserves added during the year. The Corporation, industry analysts, and
investors use such metrics to measure a Corporation’s ability to establish a
long-term trend of adding reserves at a reasonable cost.

2P Finding, development and acquisition costs per barrel of oil equivalent
(BOE) represent property acquisition, exploration, and development costs
incurred per BOE of Total Proved + Probable reserves added during the year. The
Corporation, industry analysts, and investors use such metrics to measure a
Corporation’s ability to establish a long-term trend of adding reserves at a
reasonable cost.

“RLI” Reserve Life Index is calculated by dividing a category of year end
reserves by expected current production rate.

With the finding and development costs, the aggregate of the exploration and
development costs incurred in the most recent financial year and the change
during that year in estimated future development costs generally will not
reflect total finding and development costs related to reserve additions for
that year.

Unaudited Financial Information

Certain financial and operating results included in this news release include
net debt, capital expenditures, production information and operating costs
based on unaudited estimated results. These estimated results are subject to
change upon completion of the Corporation’s audited financial statements for
the year ended December 31, 2016, and changes could be material. Canacol
anticipates filing its audited financial statements and related management’s
discussion and analysis for the year ended December 31, 2016 on SEDAR on or
before March 31, 2017.

This press release contains a number of oil and gas metrics, including F&D,
FD&A, reserve replacement and RLI, which do not have standardized meanings or
standard methods of calculation and therefore such measures may not be
comparable to similar measures used by other companies. Such metrics have been
included herein to provide readers with additional measures to evaluate the
Corporation’s performance; however, such measures are not reliable indicators
of the future performance of the Corporation and future performance may not
compare to the performance in previous periods

– END RELEASE – 27/03/2017

For further information:
Investor Relations
214-235-4798
IR@canacolenergy.com
www.canacolenergy.com

COMPANY:
FOR: CANACOL ENERGY LTD.
TSX SYMBOL: CNE
BVC SYMBOL: CNEC
OTCQX SYMBOL: CNNEF

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170327CC0122

Press Release from Marketwired 1-866-736-3779

All press releases are written by the client and have NO affiliation with the news copy written by The Canadian Press. Any questions that arise due to the content or information provided in the press release should be directed to the company/organization
issuing the release, not to The Canadian Press.

FOR: CANACOL ENERGY LTD.
TSX SYMBOL: CNE
BVC SYMBOL: CNEC
OTCQX SYMBOL: CNNEF

Date issue: March 27, 2017
Time in: 6:07 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 27, 2017) – Canacol Energy Ltd.
(“Canacol” or the “Corporation”) (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to
report its financial results for the year ended December 31, 2016. Dollar
amounts are expressed in United States dollars, except as otherwise noted.

Charle Gamba, President and CEO of the Corporation, commented: “2016 saw the
emergence of Canacol as a premier gas producer in Colombia. By April 2016, we
had achieved our goal of 90 million standard cubic feet per day (“MMscfpd”) of
gas production. As a result of the increased gas sales, our adjusted petroleum
and natural gas revenues after royalties increased 43% to $173.2 million for
the year ended December 31, 2016 compared to $121.5 million in 2015; our
adjusted funds from operations increased 122% to $113 million for the year
ended December 31, 2016 compared to $51 million in 2015; our EBITDAX increased
101% to $135.5 million for the year ended December 31, 2016 compared to $67.4
million in 2015; and we posted comprehensive income of $23.6 million in 2016.
After achieving the 90 MMscfpd milestone, several significant new 2016 gas
discoveries drive our reserve and production base towards our December 1, 2017
target of 130 MMscfpd, and our December 1, 2018 target of 230 MMscfpd, which
will place Canacol as the second largest gas producer in Colombia behind the
state oil company.

Our industry leading 2015/2016 average gas F&D of $2.52/boe ($0.44/Mcf),
combined with our very low operating expenses and robust long term gas
contracts denominated in US dollars, ensure that our current and future gas
production will yield consistently high netbacks and margins for our
shareholders. This operating base in conjunction with the financial flexibility
achieved by the closing of the February, 2017 $265 million senior secured term
loan, led by Credit Suisse, provides a solid platform for our targeted growth.
For 2017, management’s primary goals are to 1) achieve a gas production rate of
130 MMscfpd by December 1, 2017 via the construction of a new private gas
pipeline, 2) drill three gas exploration wells to continue to build the
Corporation’s gas reserves base at industry leading F&D costs, and 3) drill two
oil exploration wells to increase oil production and satisfy exploration
commitments to the ANH.

With respect to the new private gas pipeline, a Special Purpose Vehicle (“SPV”)
has been formed to build and operate a six inch pipeline that will transport 40
MMscfpd of gas from the Corporation’s Jobo gas processing facility to Sincelejo
/ Bremen approximately 80 kilometers (“kms”) to the north, where the private
pipeline will connect to the Promigas operated pipeline that ships gas to
Cartagena. Canacol has executed a ten year take-or-pay contract for 40 MMscfpd
of gas at contractual terms comparable to the Corporation’s current US dollar
denominated gas sale contracts. A bank has been retained to raise the $60
million that the SPV will require to complete the pipeline outside of Canacol.
In the meantime, the SPV is acquiring all of the right of ways required for the
pipeline, and is tendering all of the major contracts which would include
tubulars and compression. The Corporation anticipates that the pipeline will be
in operation on December 1, 2017. The productive capacity of the Corporation’s
currently producing wells is approximately 195 MMscfpd, and that of the
Corporation’s gas processing facilities approximately 200 MMscfpd.

Canacol has also spud the Canahuate-1 gas exploration well and the Pumara-1 oil
exploration well. The Canahuate-1 exploration well, located on the Esperanza
E&P Contract (100% operated working interest), was spud on March 24, 2017. The
Canahuate-1 well is located approximately three kms north of the Corporation’s
Jobo gas processing facility and is targeting gas bearing sandstones within the
proven producing Cienaga de Oro reservoir. Over the past three years, six of
the seven exploration wells drilled by the Corporation on its gas blocks,
including the Esperanza E&P contract, have resulted in commercial gas
discoveries. The Canahuate-1 well is expected to take approximately six weeks
to drill and test.

Canacol also maintains a large inventory of light oil drill ready production
and exploration opportunities. The Corporation will spud the Pumara-1
exploration well on the LLA-23 E&P Contract (100% operated working interest) on
March 31, 2017. The Pumara-1 exploration well is located three kms north of the
Labrador field and is targeting light oil bearing reservoirs within the proven
producing C7, Mirador, Gacheta and Ubaque reservoirs. Over the past four years,
five of the six exploration wells drilled by the Corporation on the LLA-23
contract have resulted in commercial light oil discoveries. The Pumara-1 well
is expected to take approximately five weeks to drill and test, and if
successful, it will be placed immediately on permanent production via the
Corporation’s oil processing facilities located at Pointer.

With the 2017 capital program to be funded by a combination of existing working
capital and cash flows, Canacol is well positioned to continue to build
production and revenues despite the uncertainty and volatility associated with
global oil prices, especially with a near to mid term global outlook of “low
oil prices for longer”. It is important to point out that approximately 90% of
our current production revenues are not impacted by global oil prices, and that
the Corporation’s debt facility is not subject to redetermination should oil
prices fall. Our financial strength, coupled with Canacol’s outstanding
exploration drilling and commercialization track record, provides a solid
platform which will allow us to reach our target of 230 MMscfpd of gas
production exiting 2018.

The Corporation anticipates releasing an update on its Mono Capuchino-1
exploration well on March 28, 2017 and its 2017 guidance during the week of
April 3, 2017.”

During 2016, the Corporation had many operational and financial accomplishments:

/T/

— The drilling and completion of the Oboe-1 exploration well and its

combined test results of 66 MMscfpd in March 2016.
— The completion of the Promigas pipeline and the Promisol Jobo gas plant
upgrade in April 2016, which allowed Canacol to increase gas production
to 90 MMscfpd. Canacol’s total current gas processing capability is 200
MMscfpd.
— The drilling and completion of the Nispero-1 exploration well and its
test result of 28 MMscfpd in August 2016.
— The completion of the first and second tranche of private placement
offerings of 9,687,670 and 1,800,000 common shares of the Corporation,
respectively, issued at C$4.08 per common share for a total of C$46.9
million in August 2016.
— The drilling and completion of the Trombon-1 exploration well and its
test result of 26 MMscfpd in October 2016.
— The drilling and completion of the Nelson-6 exploration well and its
test result of 23 MMscfpd in November 2016.
— The initiation of a private pipeline venture in November, 2016 that will
deliver 40 MMscfpd of new gas production to new and existing customers
located on the Caribbean coast in December 2017, thereby increasing the
Corporation’s transportation capacity from its current 90 MMscfpd to 130
MMscfpd upon completion.
— The execution of the agreement with Promigas in November 2016 to expand
the existing gas distribution network currently used by the Corporation
to accommodate an additional 100 MMscfpd of new gas transportation and
sales, thereby increasing the Corporation’s transportation capacity to
230 MMscfpd in December 2018.
— The drilling and completion of the Clarinete-3 development well and its
test result of 18 MMscfpd in December 2016.
— The Nelson-5 Porquero recompletion and its test result of 13 MMscfpd in
December 2016.

/T/

Highlights for the Three Months Ended December 31, 2016
(in thousands of United States dollars, except as otherwise noted; production
is stated as working-interest before royalties)

Financial and operating highlights of the Corporation include:

/T/

— Realized contractual sales volumes increased 96% to 18,310 boepd for the

three months ended December 31, 2016 compared to 9,359 boepd for the
same period in 2015. The increase is primarily due to an increase in gas
production in the Esperanza and VIM-5 blocks as a result of the
additional sales related to the Promigas pipeline expansion.
— Average daily production volumes increased 96% to 17,728 boepd for the
three months ended December 31, 2016 compared to 9,064 boepd for the
same period in 2015. The increase is primarily due to an increase in gas
production in the Esperanza and VIM-5 blocks as a result of the
additional sales related to the Promigas pipeline expansion.
— Adjusted funds from operations for the three months ended December 31,
2016 increased 395% to $42 million compared to $8.5 million for the same
period in 2015. Adjusted funds from operations are inclusive of results
from the Ecuador Incremental Production Contract (the “Ecuador IPC”)
(see full discussion in MD&A). The increase in adjusted funds from
operations is primarily the result of additional sales related to the
Promigas pipeline expansion and an increase in benchmark crude oil
prices.
— Petroleum and natural gas revenues for the three months ended December
31, 2016 increased 141% to $42 million compared to $17.4 million for the
same period in 2015. Adjusted petroleum and natural gas revenues,
inclusive of revenues related to the Ecuador IPC, for the three months
ended December 31, 2016 increased 93% to $47.9 million compared to $24.9
million for the same period in 2015. The increase is primarily the
result of additional sales related to the Promigas pipeline expansion.
— Average corporate operating netback for the three months ended December
31, 2016 increased 9% to $24/boe compared to $21.96/boe for the same
period in 2015. Operating corporate netback is inclusive of results from
the Ecuador IPC.
— The Corporation recorded a comprehensive income of $20.3 million for the
three months ended December 31, 2016 despite the non-cash impairment
charge of $37.3 million, mainly due to the execution of its tax planning
strategies which significantly reduced income tax expense. The
Corporation recognized a current income tax recovery of $6.3 million and
a deferred income tax recovery of $42.3 million during the three months
ended December 31, 2016 despite its $42 million adjusted funds from
operations.
— Capital expenditures for the three months and year ended December 31,
2016 were $58.6 million and $107.9 million, respectively, while adjusted
capital expenditures, inclusive of amounts related to the Ecuador IPC,
were $59.7 million and $110.2 million, respectively.
— At December 31, 2016, the Corporation had $66.3 million in cash and
$62.1 million in restricted cash.

—————————————————————————-

Three Three Twelve
months months Months
ended ended ended
December 31,December 31, December 31,
Financial 2016 2015 Change 2016
—————————————————————————-

Petroleum and natural gas
revenues, net of royalties 41,967 17,402 141% 147,985
Adjusted petroleum and natural
gas revenues, net of
royalties(2) 47,943 24,883 93% 173,184

Cash provided by operating
activities 30,289 4,974 509% 73,577
Per share – basic ($) 0.17 0.03 467% 0.44
Per share – diluted ($) 0.17 0.03 467% 0.44

Adjusted funds from operations
(1) (2) 41,979 8,473 395% 113,019
Per share – basic ($) 0.24 0.05 380% 0.68
Per share -diluted ($) 0.24 0.05 380% 0.67

Comprehensive income (loss) 20,331 (84,466) n/a 23,638
Per share – basic ($) 0.12 (0.54) n/a 0.14
Per share – diluted ($) 0.12 (0.54) n/a 0.14

Capital expenditures, net,
including acquisitions 58,638 22,394 162% 107,930
Adjusted capital expenditures,
net, including acquisitions
(1)(2) 59,691 22,867 161% 110,224

———————————————————————-

Six Twelve
months months
ended ended
December 31, June 30,
Financial 2015Change 2015 Change
———————————————————————-

Petroleum and natural gas
revenues, net of royalties 39,360 276% 149,047 (1%)
Adjusted petroleum and natural
gas revenues, net of
royalties(2) 54,782 216% 177,937 (3%)

Cash provided by operating
activities 19,276 282% 64,445 14%
Per share – basic ($) 0.14 214% 0.58 (24%)
Per share – diluted ($) 0.13 238% 0.58 (24%)

Adjusted funds from operations
(1) (2) 23,690 377% 87,395 29%
Per share – basic ($) 0.17 300% 0.79 (14%)
Per share -diluted ($) 0.16 319% 0.78 (14%)

Comprehensive income (loss) (103,495) n/a (106,022) n/a
Per share – basic ($) (0.72) n/a (0.96) n/a
Per share – diluted ($) (0.72) n/a (0.96) n/a

Capital expenditures, net,
including acquisitions 44,693 141% 217,342 (50%)
Adjusted capital expenditures,
net, including acquisitions
(1)(2) 48,947 125% 243,108 (55%)
December 31, December 31,
2016 2015
———————————-

Cash 66,283 43,257 53%
Restricted cash 62,073 61,721 1%
Working capital surplus, excluding non-
cash items and current portion of bank
debt(1) 64,899 46,310 40%
Current and long-term bank debt 250,638 248,228 1%
Total assets 787,508 668,349 18%

Common shares, end of period (000s) 174,359 159,266 9%
Three Three
months months
Operating ended ended
December 31, December 31,

2016 2015 Change
—————————————————————————-

Petroleum and natural gas production,
before royalties (boepd)

Petroleum (2) 3,616 5,523 (35%)
Natural gas 14,112 3,541 299%
Total (2) 17,728 9,064 96%

Petroleum and natural gas sales, before
royalties (boepd)

Petroleum (2) 3,657 5,468 (33%)
Natural gas 13,986 3,542 295%
Total (2) 17,643 9,010 96%

Realized contractual sales, before
royalties (boepd)

Natural gas 14,653 3,891 277%
Crude oil 2,026 3,390 (40%)
Ecuador (tariff oil) (2) 1,631 2,078 (22%)
Total (2) 18,310 9,359 96%

Operating netbacks ($/boe) (1)

Esperanza (natural gas) 26.35 24.03 10%
VIM-5 (natural gas) 21.99 20.78 6%
LLA-23 (oil) 14.80 12.02 23%
Ecuador (tariff oil) (2) 38.54 38.54 –
Total (2) 24.00 21.96 9%
—————————————————————————-

Twelve Six
months months
Operating ended ended
December 31, December 31,

2016 2015Change
————————————————————————–

Petroleum and natural gas production,
before royalties (boepd)

Petroleum (2) 4,012 6,253 (36%)
Natural gas 11,930 3,507 240%
Total (2) 15,942 9,760 63%

Petroleum and natural gas sales, before
royalties (boepd)

Petroleum (2) 4,019 6,370 (37%)
Natural gas 11,830 3,499 238%
Total (2) 15,849 9,869 61%

Realized contractual sales, before
royalties (boepd)

Natural gas 12,357 3,674 236%
Crude oil 2,315 4,253 (46%)
Ecuador (tariff oil) (2) 1,704 2,117 (20%)
Total (2) 16,376 10,044 63%

Operating netbacks ($/boe) (1)

Esperanza (natural gas) 27.15 23.27 17%
VIM-5 (natural gas) 23.68 20.78 14%
LLA-23 (oil) 12.05 16.74 (28%)
Ecuador (tariff oil) (2) 38.54 38.54 –
Total (2) 24.92 22.38 11%
————————————————————————–

Twelve
months
Operating ended
June 30,

2015 Change
—————————————————————

Petroleum and natural gas production,
before royalties (boepd)

Petroleum (2) 7,999 (50%)
Natural gas 3,505 240%
Total (2) 11,504 39%

Petroleum and natural gas sales, before
royalties (boepd)

Petroleum (2) 8,010 (50%)
Natural gas 3,512 237%
Total (2) 11,522 38%

Realized contractual sales, before
royalties (boepd)

Natural gas 3,512 252%
Crude oil 6,083 (62%)
Ecuador (tariff oil) (2) 1,927 (12%)
Total (2) 11,522 42%

Operating netbacks ($/boe) (1)

Esperanza (natural gas) 20.62 32%
VIM-5 (natural gas) – n/a
LLA-23 (oil) 34.91 (65%)
Ecuador (tariff oil) (2) 38.54 –
Total (2) 28.05 (11%)
—————————————————————
(1) Non-IFRS measure – see “Non-IFRS Measures” section within MD&A.
(2) Inclusive of amounts related to the Ecuador IPC – see “Non-IFRS
Measures” section within MD&A.

/T/

The Corporation’s has filed its audited consolidated financial statements and
related Management’s Discussion and Analysis and Annual Information Form as of
and for the year ended December 31, 2016 with Canadian securities regulatory
authorities. These filings are available for review on SEDAR at www.sedar.com.

Canacol is an exploration and production company with operations focused in
Colombia, Ecuador and Mexico. The Corporation’s common stock trades on the
Toronto Stock Exchange, the OTCQX in the United States of America, the Colombia
Stock Exchange and the Mexico Stock Exchange under ticker symbols CNE, CNNEF,
CNEC and CNEN respectively.

This press release contains certain forward-looking statements within the
meaning of applicable securities law. Forward-looking statements are frequently
characterized by words such as “plan”, “expect”, “project”, “intend”,
“believe”, “anticipate”, “estimate” and other similar words, or statements that
certain events or conditions “may” or “will” occur, including without
limitation statements relating to estimated production rates from the
Corporation’s properties and intended work programs and associated timelines.
Forward-looking statements are based on the opinions and estimates of
management at the date the statements are made and are subject to a variety of
risks and uncertainties and other factors that could cause actual events or
results to differ materially from those projected in the forward-looking
statements. The Corporation cannot assure that actual results will be
consistent with these forward looking statements. They are made as of the date
hereof and are subject to change and the Corporation assumes no obligation to
revise or update them to reflect new circumstances, except as required by law.
Information and guidance provided herein supersedes and replaces any forward
looking information provided in prior disclosures. Prospective investors should
not place undue reliance on forward looking statements. These factors include
the inherent risks involved in the exploration for and development of crude oil
and natural gas properties, the uncertainties involved in interpreting drilling
results and other geological and geophysical data, fluctuating energy prices,
the possibility of cost overruns or unanticipated costs or delays and other
uncertainties associated with the oil and gas industry. Other risk factors
could include risks associated with negotiating with foreign governments as
well as country risk associated with conducting international activities, and
other factors, many of which are beyond the control of the Corporation. Other
risks are more fully described in the Corporation’s most recent Management
Discussion and Analysis (“MD&A”) and Annual Information Form, which are
incorporated herein by reference and are filed on SEDAR at www.sedar.com.
Average production figures for a given period are derived using arithmetic
averaging of fluctuating historical production data for the entire period
indicated and, accordingly, do not represent a constant rate of production for
such period and are not an indicator of future production performance. Detailed
information in respect of monthly production in the fields operated by the
Corporation in Colombia is provided by the Corporation to the Ministry of Mines
and Energy of Colombia and is published by the Ministry on its website; a
direct link to this information is provided on the Corporation’s website.
References to “net” production refer to the Corporation’s working- interest
production before royalties.

Use of Non-IFRS Financial Measures – Due to the nature of the equity method of
accounting the Corporation applies under IFRS 11 to its interest in the Ecuador
IPC, the Corporation does not record its proportionate share of revenues and
expenditures as would be typical in oil and gas joint interest arrangements.
Management has provided supplemental measures of adjusted revenues and
expenditures, which are inclusive of the Ecuador IPC, to supplement the IFRS
disclosures of the Corporation’s operations in this press release. Such
supplemental measures should not be considered as an alternative to, or more
meaningful than, the measures as determined in accordance with IFRS as an
indicator of the Corporation’s performance, and such measures may not be
comparable to that reported by other companies. This press release also
provides information on adjusted funds from operations. Adjusted funds from
operations is a measure not defined in IFRS. It represents cash provided by
operating activities before changes in non-cash working capital and
decommissioning obligation expenditures, and includes the Corporation’s
proportionate interest of those items that would otherwise have contributed to
funds from operations from the Ecuador IPC had it been accounted for under the
proportionate consolidation method of accounting.
The Corporation considers adjusted funds from operations a key measure as it
demonstrates the ability of the business to generate the cash flow necessary to
fund future growth through capital investment and to repay debt. Adjusted funds
from operations should not be considered as an alternative to, or more
meaningful than, cash provided by operating activities as determined in
accordance with IFRS as an indicator of the Corporation’s performance.
The Corporation’s determination of adjusted funds from operations may not be
comparable to that reported by other companies. For more details on how the
Corporation reconciles its cash provided by operating activities to adjusted
funds from operations, please refer to the “Non-IFRS Measures” section of the
Corporation’s MD&A. Additionally, this press release references working capital
and operating netback measures. Working capital is calculated as current assets
less current liabilities, excluding non-cash items such as the current portion
of commodity contracts, the current portion of warrants, and the current
portion of any embedded derivatives asset/liability, and is used to evaluate
the Corporation’s financial leverage. Operating netback is a benchmark common
in the oil and gas industry and is calculated as total petroleum and natural
gas sales, less royalties, less production and transportation expenses,
calculated on a per barrel of oil equivalent basis of sales volumes using a
conversion. Operating netback is an important measure in evaluating operational
performance as it demonstrates field level profitability relative to current
commodity prices. Working capital and operating netback as presented do not
have any standardized meaning prescribed by IFRS and therefore may not be
comparable with the calculation of similar measures for other entities.

Operating netback is defined as revenues less royalties and production and
transportation expenses.

Realized contractual gas sales is defined as gas produced and sold plus gas
revenues received from nominated take or pay contracts.

Total cash sales is defined as realized contractual gas sales and crude oil
sales plus cash received for gas classified as deferred income according to
IFRS.

The reserves evaluations, effective December 31, 2016, were conducted by the
Corporation’s independent reserves evaluators DeGolyer and MacNaughton (“D&M”)
and Petrotech Engineering Ltd. (“Petrotech”) and are in accordance with
National Instrument 51-101 – Standards of Disclosure for Oil and Gas
Activities. The reserves are provided on a Canacol working interest before
royalty basis in units of barrels of oil equivalent using a forecast price
deck, adjusted for quality, in US dollars. The estimated values may or may not
represent the fair market value of the reserve estimates.

“proved reserves” are those reserves that can be estimated with a high degree
of certainty to be recoverable. It is likely that the actual remaining
quantities recovered will exceed the estimated proved reserves;

“probable reserves” are those additional reserves that are less certain to be
recovered than proved reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated
proved plus probable reserves;

“deemed volumes” means those volumes produced under a service agreement in
which the Corporation does not have a direct interest, but represents reserves
attributable to the Corporation as calculated using the cash flow divided by
the fixed tariff price over the life of the reserves. The Corporation has a
non-operated 25% equity participation interest in the Ecuador IPC for which it
receives a fixed price tariff for each incremental barrel produced;

Boe Conversion – “boe” barrel of oil equivalent is derived by converting
natural gas to oil in the ratio of 5.7 Mcf of natural gas to one bbl of oil. A
BOE conversion ratio of 5.7 Mcf to 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead. As the value ratio between natural gas and
crude oil based on the current prices of natural gas and crude oil is
significantly different from the energy equivalency of 5.7:1, utilizing a
conversion on a 5.7:1 basis may be misleading as an indication of value. In
this news release, the Corporation has expressed Boe using the Colombian
conversion standard of 5.7 Mcf: 1 bbl required by the Ministry of Mines and
Energy of Colombia.

F&D – Finding and development costs on a 2P (Total Proved plus Probable) basis.

With the F&D costs, the aggregate of the exploration and development costs
incurred in the most recent financial year and the change during that year in
estimated future development costs generally will not reflect total finding and
development costs related to reserve additions for that year.

This press release contains a number of oil and gas metrics, including F&D,
FD&A, reserve replacement and RLI, which do not have standardized meanings or
standard methods of calculation and therefore such measures may not be
comparable to similar measures used by other companies. Such metrics have been
included herein to provide readers with additional measures to evaluate the
Corporation’s performance; however, such measures are not reliable indicators
of the future performance of the Corporation and future performance may not
compare to the performance in previous periods.

– END RELEASE – 27/03/2017

For further information:
Investor Relations
+1 (214) 235-4798
IR@canacolenergy.com
www.canacolenergy.com

COMPANY:
FOR: CANACOL ENERGY LTD.
TSX SYMBOL: CNE
BVC SYMBOL: CNEC
OTCQX SYMBOL: CNNEF

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170327CC0116

Press Release from Marketwired 1-866-736-3779

All press releases are written by the client and have NO affiliation with the news copy written by The Canadian Press. Any questions that arise due to the content or information provided in the press release should be directed to the company/organization
issuing the release, not to The Canadian Press.

FOR: WESTCORE ENERGY LTD.TSX VENTURE SYMBOL: WTRDate issue: March 27, 2017Time in: 5:53 PM eAttention:
SASKATOON, SASKATCHEWAN–(Marketwired – March 27, 2017) – Westcore Energy Ltd.
(“Westcore” or the “Company”) (TSX VENTURE:WTR) announces that it has …

FOR: ENBRIDGE INC.
TSX SYMBOL: ENB
NYSE SYMBOL: ENB

Date issue: March 27, 2017
Time in: 4:52 PM e

Attention:

CALGARY, ALBERTA–(Marketwired – March 27, 2017) –

NOT FOR DISTRIBUTION IN THE UNITED STATES OR OVER U.S. NEWSWIRE SERVICES

Enbridge Inc. (TSX:ENB) (NYSE:ENB) (Enbridge or the Company) announced today
that it and Enbridge Income Fund Holdings Inc. (TSX:ENF) (EIFH) have entered
into an agreement with a syndicate of underwriters (the Underwriters) led by
BMO Capital Markets, CIBC Capital Markets and Scotiabank, pursuant to which the
Underwriters have agreed to purchase, and Enbridge has agreed to sell, on a
bought deal basis, 15,085,000 EIFH common shares (the Common Shares) at a price
of $33.15 per Common Share (the Secondary Offering Price) for distribution to
the public, for gross proceeds to Enbridge of approximately $0.5 billion (the
Secondary Offering). The closing of the Secondary Offering is expected to occur
on or about April 18, 2017.

The Underwriters have also been granted an option to purchase up to an
additional 2,262,750 common shares of EIFH from Enbridge at the issue price to
cover over-allotments, if any. If exercised in full, Enbridge will receive
additional gross proceeds of approximately $75.0 million. The over-allotment
option is exercisable, in whole or in part, by the Underwriters at any time up
to 30 days after the closing of the Secondary Offering.

The proceeds of the Secondary Offering will initially be used by Enbridge to
pay down short-term debt, pending reinvestment by Enbridge in its growing
portfolio of secured projects. In September of 2016 at the time of the
announcement of its merger with Spectra Energy Corp, Enbridge also announced
its intention to divest or monetize up to $2.0 billion of assets over the
ensuing 12 months to further bolster its financial strength and flexibility. To
date, the Company has raised, enterprise wide, approximately $1.7 billion
through the sale by the Fund Group (made up of Enbridge Income Fund, Enbridge
Commercial Trust and Enbridge Income Partners LP) of the South Prairie Region
liquids pipeline assets and the divestiture of other assets and investments.
With the completion of this Secondary Offering, the Company will have more than
achieved its previously announced monetization target.

Immediately prior to the closing of the Secondary Offering, Enbridge will
exchange ordinary units of Enbridge Income Fund for an equivalent amount of
common shares of EIFH. In order to maintain its 19.9 percent interest in EIFH,
Enbridge will retain a portion of the common shares issued pursuant to such
exchange and sell the balance under the Secondary Offering. EIFH will not
receive any proceeds from the Secondary Offering and Enbridge will pay all
expenses and fees associated with the offering. Upon completion of the
Secondary Offering, Enbridge’s economic interest in the Fund Group will be
reduced from 86.9 percent to 84.9 percent (84.6 percent if the over-allotment
option is exercised in full).

“This transaction is expected to be neutral in 2017, but increasingly accretive
to Enbridge’s ACFFO/share over the Company’s planning horizon,” said John
Whelen, Executive Vice President and Chief Financial Officer. “It accomplishes
two important strategic initiatives. First, it enables us to more than achieve
the asset monetization target we announced last fall, earlier than planned,
bolstering the balance sheet and positioning the Company to grow post
combination with Spectra Energy Corp. Second, it furthers our previously
communicated objective to gradually increase the public’s economic interest in
the Fund Group to approximately 20 percent over time and increase EIFH’s public
market capitalization and trading liquidity. The sale of the South Prairie
Region assets late last year was more than sufficient to meet the Fund Group’s
equity financing needs through the end of 2017. With its near term equity
requirements taken care of, EIFH had additional capacity to accommodate a
secondary offering by Enbridge this year.”

Going forward, Enbridge will continue to hold a very significant economic
interest in the Fund Group which holds key assets within the larger Enbridge
asset portfolio. The Company is not contemplating any further secondary
offerings of EIFH shares at this time and expects that the public’s interest in
the Fund Group will grow to the communicated 20 percent target over the medium
term planning horizon as EIFH raises equity from the public to fund the secured
capital program being undertaken by the Fund Group.

This news release does not constitute an offer to sell or a solicitation of an
offer to buy the Common Shares in any jurisdiction. The Common Shares offered
have not been registered under the United State Securities Act of 1933, as
amended, and may not be offered or sold within the United States.

Forward-Looking Statements Regarding Enbridge Inc.

Certain information provided in this news release constitutes forward-looking
statements. The words “anticipate”, “expect”, “project”, “estimate”, “forecast”
and similar expressions are intended to identify such forward-looking
statements. Forward-looking statements contained in this news release include,
but are not limited to, statements with respect to the Secondary Offering,
including the closing date thereof, the use of proceeds, the achievement of the
Company’s asset monetization target, the Company’s resulting balance sheet and
growth position, the increased liquidity for public shareholders of EIFH
resulting from the Secondary Offering, the Company’s intention to increase the
public’s economic interest in the Fund Group, the impact of the Secondary
Offering on the Company’s ACFFO over the term of the Company’s strategic plan,
the Fund Group’s equity funding needs, Enbridge’s intentions with respect to
its economic interest in the Fund Group and any future secondary offerings.
Although the Company believes that these statements are based on information
and assumptions which are current, reasonable and complete, these statements
are necessarily subject to a variety of assumptions, risks and uncertainties
pertaining, but not limited to, the timing and completion of the Secondary
Offering and other asset monetization transactions; estimated future cash flow
and dividends; expected ACFFO; financial strength and flexibility; debt and
equity market conditions; project construction and completion; in-service
dates; operating performance; regulatory parameters; weather; economic and
competitive conditions; exchange rates, inflation and interest rates; changes
in tax law and tax rates; counterparty risk; and supply of and demand for
commodities and commodity prices. A further discussion of the risks and
uncertainties facing the Company can be found in the Company’s filings with
Canadian and United States securities regulators. While the Company makes these
forward-looking statements in good faith, should one or more of these risks or
uncertainties materialize, or should underlying assumptions prove incorrect,
actual results may vary significantly from those expected. Except as may be
required by applicable securities laws, the Company assumes no obligation to
publicly update or revise any forward-looking statements made herein or
otherwise, whether as a result of new information, future events or otherwise.

Non-GAAP Measures

This news release makes reference to non-GAAP measures, including ACFFO and
ACFFO per share. ACFFO is defined as cash flow provided by operating activities
before changes in operating assets and liabilities (including changes in
environmental liabilities) less distributions to non-controlling interests and
redeemable non-controlling interests, preference share dividends and
maintenance capital expenditures, and further adjusted for unusual,
non-recurring or non-operating factors. Management of Enbridge believes the
presentation of these measures gives useful information to investors and
shareholders as they provide increased transparency and insight into the
performance of Enbridge. Management of Enbridge uses ACFFO to assess
performance and to set its dividend payout target. These measures are not
measures that have a standardized meaning prescribed by generally accepted
accounting principles in the United States of America (U.S. GAAP) and may not
be comparable with similar measures presented by other issuers. Additional
information on Enbridge’s use of non-GAAP measures can be found in Enbridge’s
Management’s Discussion and Analysis (MD&A) available on Enbridge’s website and
www.sedar.com.

About Enbridge Inc.

Enbridge Inc. is North America’s premier energy infrastructure company with
strategic business platforms that include an extensive network of crude oil,
liquids and natural gas pipelines, regulated natural gas distribution utilities
and renewable power generation. The Company safely delivers an average of 2.8
million barrels of crude oil each day through its Mainline and Express
Pipelines, accounting for nearly 68% of U.S.-bound Canadian crude oil
production, and moves approximately 20% of all natural gas consumed in the U.S.
serving key supply basins and demand markets. The Company’s regulated utilities
serve approximately 3.5 million retail customers in Ontario, Quebec, New
Brunswick and New York State. Enbridge also has a growing involvement in
electricity infrastructure with interests in more than 2,500 MW of net
renewable generating capacity, and an expanding offshore wind portfolio in
Europe. The Company has ranked on the Global 100 Most Sustainable Corporations
index for the past eight years; its common shares trade on the Toronto and New
York stock exchanges under the symbol ENB.

Life takes energy and Enbridge exists to fuel people’s quality of life. For
more information, visit www.enbridge.com

– END RELEASE – 27/03/2017

For further information:
Enbridge Inc. – Media
Suzanne Wilton
(403) 231-7385 or Toll Free: (888) 992-0997
suzanne.wilton@enbridge.com
OR
Enbridge Inc. – Investment Community
Jonathan Gould
(403) 231-3916 or Toll Free: (800) 481-2804
jonathan.gould@enbridge.com

COMPANY:
FOR: ENBRIDGE INC.
TSX SYMBOL: ENB
NYSE SYMBOL: ENB

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170327CC0112

Press Release from Marketwired 1-866-736-3779

All press releases are written by the client and have NO affiliation with the news copy written by The Canadian Press. Any questions that arise due to the content or information provided in the press release should be directed to the company/organization
issuing the release, not to The Canadian Press.

CALGARY — Oil production remains offline two weeks after a fire halted operations at the Syncrude oilsands mining complex in northern Alberta but its largest owner says it still expects to meet 2017 targets.

Suncor Energy Inc. (TSX:SU) said Monday it was still on track to meet its guidance issued in November of between 680,000 and 720,000 barrels of crude per day, in part because of strong results from its other oilsands and offshore assets. The company’s forecast called for between 150,000 and 165,000 bpd this year from its 54 per cent stake in Syncrude.

Analyst Arthur Grayfer of CIBC Capital Markets said in a note Monday that Syncrude had built up a “cushion” of production by averaging more than 95 per cent of capacity in January and February, above its 2017 average forecast of 84 per cent.

Suncor said some of the impact of the unplanned outage will be offset by advancing an eight-week maintenance turnaround that was originally scheduled to begin next month.

The fire erupted on March 14 at the Mildred Lake oilsands upgrader after a pipeline began leaking near one of its two hydrotreating units. It burned for two days.

Syncrude said Monday a male employee remains in hospital.

While much of Syncrude’s workforce returned a day after the fire, Imperial Oil (TSX:IMO) said in a separate statement Monday that there are no shipments of synthetic crude from the operation at this time.

Imperial owns 25 per cent of Syncrude and provides management services under contract. Suncor said it will handle some of Syncrude’s untreated production, starting this week.

Suncor said it expects pipeline shipments of treated oil to resume at up to 50 per cent capacity in April.

 

Follow @HealingSlowly on Twitter.

Dan Healing, The Canadian Press

Note to readers: This is a corrected story. A previous version said Imperial Oil was the operator of Syncrude.

RIYADH, Saudi Arabia — Saudi Arabia on Monday reduced the tax rate for Saudi Aramco as plans move forward to publicly list shares of the state-owned oil giant.

The new code, rolled out by royal decree from King Salman, taxes Aramco at 50 per cent on income retroactively starting Jan. 1.

Aramco CEO Amin Nasser thanked the king in a statement for the decree reducing the company’s tax rate from what he said was 85 per cent, and said it “will bring Saudi Aramco in line with international benchmarks.”

The company’s oil production is Saudi Arabia’s main source of revenue and its finances are not publicly disclosed. The government is embarking on an overhaul of its economy to move away from heavy reliance on oil, its main export, after a sharp drop in prices.

The government is preparing to list less than 5 per cent of Aramco, possibly by next year, on the Saudi stock exchange and an international exchange. It is gearing up to be the largest flotation in history, with officials valuing Aramco at more than $2 trillion. The government would remain the company’s largest shareholder.

The London-based Capital Economics said the lower tax rate means that the company will have a greater share of its profits available to pay out as dividends to shareholders. It says the dividends going to the government will largely cover the lost tax revenue, so that the move represents “merely a shift in the way that oil revenues accrue to the government.”

Finance Minister Mohammed al-Jadaan said in a statement that the new tax code will have no impact on the government’s ability to deliver services to its citizens.

He said any tax revenue reductions “are replaced by stable dividend payments by government-owned companies, and other sources of revenue including profits resulting from investments.”

Energy Minister Khalid al-Falih also said the royal order will not negatively affect state coffers, adding that the kingdom’s hydrocarbon resources “remain sovereign.”

The decree imposes a 50 per cent tax on oil and gas producers that have invested capital of more than $100 billion in the kingdom. That figure jumps to 65 per cent for producers with between $80 billion and $100 billion in invested capital, 75 per cent if between $60 billion and $80 billion, and 85 per cent on producers with invested capital that does not exceed $60 billion.

___

Batrawy reported from Dubai, United Arab Emirates.

Abdullah Al-Shihri And Aya Batrawy, The Associated Press

PARIS — French energy company Total is launching a multi-billion-dollar petrochemical joint venture in Texas as it tries to profit from the “business-friendly environment” under the current U.S. administration.

The plan announced Monday in Paris is the company’s largest-ever investment in petrochemicals, and part of its strategy to benefit from cheap shale gas in the U.S. and President Donald Trump’s support for the energy industry.

Total will partner with chemical companies Borealis and Nova to build two new units on the U.S. Gulf Coast.

One is an ethane steam cracker in Port Arthur, Texas that would convert natural gas into chemicals used for plastics and other materials. Total would provide the initial $1.7 billion for that operation.

The other is a new polyethylene plant in Bayport, Texas, also for making plastics. The cost of that plant is still being worked out among Total, Borealis and Nova, said Bernard Pinatel, president of Total’s refining and chemicals. Overall, he said, the project would be worth several billion dollars and Total would hold 50 per cent of it.

Total says the venture, which depends on regulators’ approval, would start in 2020 and create at least 1,500 local jobs.

“We want to take advantage of the business-friendly environment” to boost Total’s 60-year presence in the U.S., CEO Patrick Pouyanne said in a statement.

Pinatel told The Associated Press that the French company is not scared away by Trump’s “America first” policies, and instead was encouraged by an “American administration favourable to everything that touches the energy sector.”

Total SA employs 6,000 people in the U.S. in the oil, gas and solar activities.

Angela Charlton, The Associated Press

FOR: BIRCHCLIFF ENERGY LTD.TSX SYMBOL: BIRDate issue: March 27, 2017Time in: 10:39 AM eAttention:
CALGARY, ALBERTA–(Marketwired – March 27, 2017) – Birchcliff Energy Ltd.
(“Birchcliff”) (TSX:BIR) is pleased to announce that Mr. Seymour Schulich has
ac…

FOR: DUNDEE ENERGY LIMITED
TSX SYMBOL: DEN

Date issue: March 27, 2017
Time in: 9:03 AM e

Attention:

TORONTO, ONTARIO–(Marketwired – March 27, 2017) – Dundee Energy Limited
(“Dundee Energy” or the “Corporation”) (TSX:DEN) today announced that the
arbitral tribunal of the International Chamber of Commerce rendered its
decision related to the Castor Project in Spain, denying the claim made by
Castor UGS Limited Partnership. The decision was rendered by a majority of the
three-person tribunal, with the third member issuing a dissenting opinion.
Counsel is reviewing the decision to determine what steps may be taken based on
the decision rendered.

ABOUT THE CORPORATION

Dundee Energy Limited is a Canadian-based oil and natural gas company with a
mandate to create long-term value for its shareholders through the exploration,
development, production and marketing of oil and natural gas, and through other
high impact energy projects. Dundee Energy holds interests, both directly and
indirectly, in the largest accumulation of producing oil and gas assets in
Ontario and, through a preferred share investment, in certain exploration and
evaluation programs for oil and natural gas offshore Tunisia. The Corporation’s
common shares trade on the Toronto Stock Exchange under the symbol “DEN”.

– END RELEASE – 27/03/2017

For further information:
Dundee Energy Limited
21st Floor,
1 Adelaide Street East
Toronto, ON M5C 2V9
OR
Dundee Energy Limited
Harold (Sonny) Gordon
Chairman
416-863-6990
OR
Dundee Energy Limited
Bruce Sherley
President & CEO
403-651-4581
www.dundee-energy.com

COMPANY:
FOR: DUNDEE ENERGY LIMITED
TSX SYMBOL: DEN

INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170327CC0053

Press Release from Marketwired 1-866-736-3779

All press releases are written by the client and have NO affiliation with the news copy written by The Canadian Press. Any questions that arise due to the content or information provided in the press release should be directed to the company/organization
issuing the release, not to The Canadian Press.

FOR: METHANEX CORPORATION
TSX SYMBOL: MX
NASDAQ SYMBOL: MEOH

Date issue: March 27, 2017
Time in: 8:30 AM e

Attention:

VANCOUVER, BRITISH COLUMBIA–(Marketwired – March 27, 2017) – Methanex
Corporation (the “Company”) (TSX:MX)(NASDAQ:MEOH) commented today on the filing
of a revised schedule 13D by its largest shareholder, M&G Investment Management
Limited of London, U.K. (“M&G”) in relation to its shareholding in Methanex.
The revised schedule 13D was filed with the US Securities Exchange Commission
on March 24, 2017 to replace an earlier version filed March 23, 2017.A schedule
13D is filed when a significant shareholder shifts from being a passive
investor to one who more actively asserts an agenda with management. M&G
currently owns around 17.5 million shares or approximately 19.5% of the issued
and outstanding shares of Methanex and has been a shareholder since 2007.

In their 13D filing, M&G cited that they believe that Methanex’s market
valuation does not reflect its intrinsic value, and encourages management to
use all excess cash, with the exception of potential modest capital
expenditures to refurbish Methanex’s Chilean assets, towards share buybacks.

John Floren, President and CEO of Methanex commented, “We understand M&G’s
frustration with Methanex’s share valuation and we believe that M&G’s views are
quite aligned with our strategy with respect to capital allocation. We have a
long track record of a disciplined approach to capital allocation and of
returning cash to shareholders, while maintaining a prudent balance sheet and
liquidity given the cyclical nature of our business. Over the last 20 years we
have repurchased over half of the company’s shares outstanding, and we have
grown our dividend every year except during the 2009-2010 financial crisis and
during 2016, when we maintained our dividend despite very low methanol prices.
Consistent with our strategy, on March 6 we announced a Normal Course Issuer
Bid (“NCIB”) for up to 5% of issued and outstanding shares. We also remain
committed to a meaningful and growing dividend that is sustainable at the
bottom of cycle methanol prices.”

Mr. Floren continued, “In recent years we have invested approximately $2
billion to add over 3 million tonnes of high quality methanol production at an
advantaged capital cost significantly below current estimated replacement cost.
This major capital expansion is now behind us. We have modest maintenance
capital and financing requirements in the next two years and our next bond
maturity is at the end of 2019. We also have an excellent potential opportunity
to invest in our Chile site. We are optimistic that we will be able to secure
additional gas to support an investment in the restart of our Chile IV plant,
and expect to be in a position to make a decision by mid-2017 to spend
approximately $50 million over 12 months. If we are successful in securing
sufficient gas to support a two-plant operation, we would expect to spend
around an additional $50 million approximately in mid-2018 to refurbish the
Chile I plant. We believe these investments would make excellent business sense
as they represent a high return on investment and a very low capital cost
opportunity to grow the business and return value quickly to shareholders.”

Mr. Floren concluded, “Our methanol production and sales volumes are at record
levels and we are currently benefiting from a stronger methanol price
environment. We have a track record of managing our balance sheet in a prudent
and fiscally responsible manner and do not intend to leverage our balance sheet
for the purpose of buying back shares. However, given our limited near-term
cash requirements, we expect to generate significant free cash flow even at
methanol prices that are lower than what we are realising in Q1 2017 and plan
to allocate the free cash to share repurchases. Assuming we are able to average
a realized price of around $400/tonne, in what is proving to be a very volatile
methanol market, we estimate that we could generate sufficient cash to complete
the NCIB within a period of approximately four months from the start date of
March 13, 2017. After completing the current NCIB on the NASDAQ, it would be
our intention to extend the NCIB on the Toronto Stock Exchange which would
allow us to use excess cash to purchase up to an additional roughly 1.7 million
shares. After completion of the extended NCIB we would have the option to
undertake a substantial issuer bid at a later date depending on the level of
cash accumulation on our balance sheet.”

Methanex is a Vancouver-based, publicly traded company and is the world’s
largest producer and supplier of methanol to major international markets.
Methanex shares are listed for trading on the Toronto Stock Exchange in Canada
under the trading symbol “MX” and on the NASDAQ Global Select Market in the
United States under the trading symbol “MEOH”.

FORWARD-LOOKING INFORMATION WARNING

This news release contains certain forward-looking statements with respect to
us and our industry. These statements relate to future events or our future
performance. All statements other than statements of historical fact are
forward-looking statements. Statements that include the words “expect”, and
“continue” or other comparable terminology and similar statements of a future
or forward-looking nature identify forward-looking statements. More
particularly and without limitation, any statements regarding the following are
forward-looking statements:

/T/

— Methanex’s expected future financial strength and cash generation

capability, and
— Methanex’s ability to continue to return excess cash to shareholders.

/T/

We believe that we have a reasonable basis for making such forward-looking
statements. The forward-looking statements in this document are based on our
experience, our perception of trends, current conditions and expected future
developments as well as other factors. Certain material factors or assumptions
were applied in drawing the conclusions or making the forecasts or projections
that are included in these forward-looking statements, including, without
limitation, future expectations and assumptions concerning the following:

/T/

— the supply of, demand for, and price of methanol, methanol derivatives,

natural gas, coal, oil and oil derivatives,
— operating rates of our facilities,
— operating costs including natural gas feedstock and logistics costs,
capital costs, tax rates, cash flows, foreign exchange rates and
interest rates,
— global and regional economic activity (including industrial production
levels).

/T/

However, forward-looking statements, by their nature, involve risks and
uncertainties that could cause actual results to differ materially from those
contemplated by the forward-looking statements. The risks and uncertainties
primarily include those attendant with producing and marketing methanol and
successfully carrying out major capital expenditure projects in various
jurisdictions, including without limitation:

/T/

— conditions in the methanol and other industries including fluctuations

in the supply, demand for and price of methanol and its derivatives,
including demand for methanol for energy uses,
— the price of natural gas, coal, oil and oil derivatives,
— the ability to successfully carry out corporate initiatives and
strategies,
— actions of competitors, suppliers and financial institutions,
— world-wide economic conditions, and
— other risks described in our 2016 Annual Management’s Discussion and
Analysis and our Fourth Quarter 2016 Management’s Discussion and
Analysis.

/T/

Having in mind these and other factors, investors and other readers are
cautioned not to place undue reliance on forward-looking statements. They are
not a substitute for the exercise of one’s own due diligence and judgment. The
outcomes anticipated in forward-looking statements may not occur and we do not
undertake to update forward-looking statements except as required by applicable
securities laws.

FURTHER INFORMATION

To view the 13D filing referenced above, investors can go to the SEC website at
www.sec.gov and search for company fillings under M&G Investment Management
Limited.

– END RELEASE – 27/03/2017

For further information:
Sandra Daycock
Director, Investor Relations
604 661-2600

COMPANY:
FOR: METHANEX CORPORATION
TSX SYMBOL: MX
NASDAQ SYMBOL: MEOH

INDUSTRY: Chemicals – Commodity Chemicals, Chemicals –
Petrochemicals, Chemicals – Plastics and fibers, Chemicals –
Specialty Chemicals, Chemicals – Wholesalers and Distributors
RELEASE ID: 20170327CC0038

Press Release from Marketwired 1-866-736-3779

All press releases are written by the client and have NO affiliation with the news copy written by The Canadian Press. Any questions that arise due to the content or information provided in the press release should be directed to the company/organization
issuing the release, not to The Canadian Press.

FOR: WESTERN ENERGY SERVICES CORP.TSX SYMBOL: WRGDate issue: March 27, 2017Time in: 7:30 AM eAttention:
CALGARY, ALBERTA–(Marketwired – March 27, 2017) –
NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN
THE UNITED STATES…

FOR: SUNCOR ENERGY INC.TSX SYMBOL: SUNYSE SYMBOL: SUDate issue: March 27, 2017Time in: 6:30 AM eAttention:
– Planned maintenance advanced to minimize outage impact
– No change expected to overall Suncor annual production guidance
CALGARY, ALBERTA–(Mar…