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Exhibit 15.3

PETROCHINA CANADA LTD.

RESERVES ASSESSMENT AND

EVALUATION OF

CANADIAN OIL AND GAS PROPERTIES

DUVERNAY AND GROUNDBIRCH ASSETS (SEC)

Effective December 31, 2017

1171386

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DUVERNAY AND GROUNDBIRCH ASSETS (SEC)

TABLE OF CONTENTS

	Page
COVER LETTER		3
INDEPENDENT PETROLEUM CONSULTANTS’ CONSENT		5
INTRODUCTION		7
SEC RESERVES DEFINITIONS		8
EVALUATION PROCEDURE		13
PRODUCT PRICE AND MARKET FORECASTS		17

2 March 02, 2018 10:55:50  

	February 20, 2017 Project 1171386

Mr. Michael Fox

PetroChina Canada Ltd.

Suite 2700, 707-5 Street SW

Calgary, Alberta T2P 1V8

Dear Sir:

Re: PetroChina Canada Ltd.

Third Party Corporate Evaluation

Duvernay and Groundbirch Assets

Effective December 31, 2017

GLJ Petroleum Consultants (GLJ) has completed an independent reserves assessment and evaluation of the oil and gas properties of PetroChina Canada Ltd. (the “Company”) as requested by the Company. The effective date of this evaluation is December 31, 2017.

This report has been prepared for the Company for the purpose of annual disclosure and other financial requirements. This evaluation has been prepared in accordance with reserves definitions, standards and procedures of the United States Securities and Exchange Commission (SEC). All values contained herein are in Canadian dollars.

It was GLJ’s primary mandate in this evaluation to provide an independent evaluation of the oil and gas reserves of the Company in aggregate. Accordingly, it may not be appropriate to extract individual property or entity estimates for other purposes. Our engagement letter notes these limitations on the use of this report.

This report represents a subset of the final corporate reserves of the Company, dated December 21, 2017. The reserves and values contained herein include the Duvernay joint venture assets (Kaybob Duvernay, Willesden Green Duvernay and Simonette Montney properties) and Groundbirch Montney asset. For further details please refer to the final SEC report of the Company dated December 21, 2017.

A summary of the reserves in barrels of oil equivalent and values for the Duvernay joint venture and Groundbirch Montney assets, as extracted from the corporate reserves report of the Company, are illustrated in the following tables.

4100, 400 - 3^rd Ave SW Calgary, AB, Canada T2P 4H2 | tel 403-266-9500 | gljpc.com

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Summary of Reserves

Company Proved Reserves

Effective December 31, 2017

	Proved Developed		Proved Undeveloped		Total Proved
Total Oil (Mbbl)
Duvernay Joint Venture		257		0		257
Groundbirch Montney		0		0		0
Total Sales Gas (MMcf)
Duvernay Joint Venture		109,975		227,762		337,738
Groundbirch Montney		22,893		0		22,893
Natural Gas Liquids (Mbbl)
Duvernay Joint Venture		14,059		27,763		41,822
Groundbirch Montney		196		0		196
Oil Equivalent (Mboe)
Duvernay Joint Venture		32,646		62,437		98,369
Groundbirch Montney		4,012		0		4,012

Summary of Values

Company Net Present Value at 10% Discount Factor

Effective December 31, 2017

Asset	Proved Developed		Proved Undeveloped		Total Proved
	($M)		($M)		($MM)
Duvernay Joint Venture		456,257		354,328		810,603
Groundbirch Montney		-5,850		0		-5,850

The volumes and values of reserves as presented for the Groundbirch Montney asset are representative of the first year of forecast production and is currently sub-economic at current commodity prices, using the SEC 2017-Dec-31 posted first day of the month, 12 month average commodity pricing. Please refer to the Duvernay and Groundbirch property reports for further details.

Please refer to the following sections for details of reserves methodology, results of the reserves evaluation and key factors used in the evaluation. It is trusted that this evaluation meets your current requirements. Should you have any questions regarding this analysis, please contact the undersigned.

Yours very truly,

GLJ PETROLEUM CONSULTANTS LTD.

Trisha S. MacDonald, P. Eng.

Manager, Engineering

TSM/JLA/ljn

Attachments

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INDEPENDENT PETROLEUM CONSULTANTS’ CONSENT

The undersigned firm of Independent Petroleum Consultants of Calgary, Alberta, Canada has prepared an independent evaluation of the PetroChina Canada Ltd. (the “Company”) Canadian oil and gas properties and hereby gives consent to the use of its name and to the said estimates. The effective date of the evaluation is December 31, 2017.

In the course of the evaluation, the Company provided GLJ Petroleum Consultants Ltd. personnel with basic information which included land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget forecasts, financial data and future operating plans. Other engineering, geological or economic data required to conduct the evaluation and upon which this report is based, were obtained from public records, other operators and from GLJ Petroleum Consultants Ltd. nonconfidential files. The Company has provided a representation letter confirming that all information provided to GLJ Petroleum Consultants Ltd. is correct and complete to the best of its knowledge. Procedures recommended in the United States Securities and Exchange Commission (SEC) to verify certain interests and financial information were applied in this evaluation. In applying these procedures and tests, nothing came to GLJ Petroleum Consultants Ltd.’s attention that would suggest that information provided by the Company was not complete and accurate. GLJ Petroleum Consultants Ltd. reserves the right to review all calculations referred to or included in this report and to revise the estimates in light of erroneous data supplied or information existing but not made available which becomes known subsequent to the preparation of this report.

The accuracy of any reserves and production estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserves and production estimates presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward.

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Revenue projections presented in this report are based in part on forecasts of market prices, currency exchange rates, inflation, market demand and government policy which are subject to many uncertainties and may, in future, differ materially from the forecasts utilized herein. Present values of revenues documented in this report do not necessarily represent the fair market value of the reserves evaluated herein.

PERMIT TO PRACTICE
GLJ PETROLEUM CONSULTANTS LTD.
Signature:
Date:	December 21, 2017
PERMIT NUMBER:    P  2066
The Association of Professional Engineers and Geoscientists of Alberta

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INTRODUCTION

GLJ Petroleum Consultants (GLJ) was commissioned by PetroChina Canada Ltd. (the “Company”) to prepare an independent evaluation of its oil and gas reserves effective December 31, 2017. The locations of the most significant reserves properties are indicated on the attached index map.

The evaluation was initiated in August 2017 and completed by December 2017. Estimates of reserves and projections of production were generally prepared using well information and production data available from public sources to approximately September 30, 2017. The Company provided land, accounting data and other technical information not available in the public domain to approximately December 15, 2017. In certain instances, the Company also provided recent engineering, geological and other information up to December 15, 2017. The Company has confirmed that, to the best of its knowledge, all information provided to GLJ is correct and complete as of the effective date.

The reserves definitions used in preparing this report (included herein under “Reserves Definitions”) are those required by the United States Securities Exchange Commission (SEC). The summary of reserves and value, using the SEC reserves definitions, uses the average historical prices derived from the first day of the month for January to December 2017.

The evaluation was conducted on the basis of the average of the first day posted prices in each of the 12 months of the Company’s fiscal year summarized in the Product Price and Market Forecasts section of this report.

Tables summarizing production, royalties, costs, revenue projections, reserves and present value estimates for various reserves categories for individual properties and the Company total are provided in the tabbed sections of this Summary Report.

The Evaluation Procedure section outlines general procedures used in preparing this evaluation. The individual property reports, provided under separate cover, provide additional evaluation details. The following summarizes evaluation matters that have been included/excluded in cash flow projections:

• The effect on projected revenues of the Company’s financial hedging activity has not been included,

• provisions for the abandonment and reclamation of all of the Company’s existing and future wells to which reserves have been attributed have been included; all other abandonment and reclamation costs have not been included,

• general and administrative (G&A) costs and overhead recovery have not been included,

• undeveloped land values have not been included.

Economic forecasts are provided on an after tax basis including tax pools provided by the Company in the “Evaluation Procedure” section.

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SEC RESERVES DEFINITIONS

The following definitions are excerpts from Regulation S-X 210.4-10. Portions of these definitions within square parentheses, [    ], have been transposed from other sections of Regulation S-X 210.4-10 to improve readability.

Resources

Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Reserves

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note: Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Proved Oil and Gas Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the

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structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) [The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.]

[Where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.]

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Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed Oil and Gas Reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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Undeveloped Oil and Gas Reserves

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir [see Other Definitions below], or by other evidence using reliable technology establishing reasonable certainty.

Other Pertinent Definitions

Analogous Reservoir

Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Reasonable Certainty

If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

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Reliable Technology

Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reservoir

A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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EVALUATION PROCEDURE

TABLE OF CONTENTS

INTEREST DESCRIPTIONS	14
WELL DATA	14
ACCOUNTING SUMMARY	14
PRODUCTION FORECASTS	14
AFTER TAX ANALYSIS	15
ECONOMIC PARAMETERS	15
OIL EQUIVALENT OR GAS EQUIVALENT	15
LIST OF ABBREVIATIONS	16

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EVALUATION PROCEDURE

The following outlines the methodology employed by GLJ Petroleum Consultants (GLJ) in conducting the evaluation of the Company’s oil and gas properties. GLJ evaluation procedures are in compliance with standards outlined in the SPE-PRMS evaluation guidelines.

INTEREST DESCRIPTIONS

The Company provided GLJ with current land interest information. The Company provided a representation letter confirming accuracy of land information. Certain cross-checks of land and accounting information were undertaken by GLJ as recommended in the COGE Handbook. In this process, nothing came to GLJ’s attention that indicated that information provided by the Company was incomplete or unreliable.

In GLJ’s reports, “Company Interest” reserves and values refer to the sum of royalty interest* and working interest reserves before deduction of royalty burdens payable. “Working Interest” reserves equate to those reserves that are referred to as “Company Gross” reserves. Reserves and values reported herein are generally consistent with disclosure rules as required by the SEC.

^*Royalty interest reserves include royalty volumes derived only from other working interest owners.

WELL DATA

Pertinent interest and offset well data such as drill stem tests, workovers, pressure surveys, production tests, etc., were provided by the Company or were obtained from other operators, public records or GLJ nonconfidential files.

ACCOUNTING SUMMARY

The Company provided GLJ with available accounting data on a property basis and for the corporate total for the period January 1, 2017, to July 31, 2017. In some circumstances this information was also provided on a cost center basis to address major reserves entities that are a subset of a Company property. The Company has also provided historical accounting data by property and corporate totals for 2015 to 2016.

PRODUCTION FORECASTS

In establishing all production forecasts, consideration was given to existing gas contracts and the possibility of contract revisions, to the operator’s plans for development drilling and to reserves and well capability. Generally, development drilling in an area was not considered unless there was some indication from the operator that drilling could be expected.

The on-stream date for currently shut-in reserves was estimated with consideration given to the following:

• proximity to existing facilities

• plans of the operator

• economics

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AFTER TAX ANALYSIS

Canadian income taxes were calculated based on currently legislated federal and provincial tax rates, tax regulations and tax pool information provided by the Company. After tax values for reserves development status or production status subcategories (i.e. developed, undeveloped, producing, non-producing) are calculated by difference.

Tax Pools

The Company provided tax pool information pertinent to the Duvernay joint venture assets and Groundbirch Montney asset. For further information regarding after tax analysis and specific tax pool information, please refer to the comprehensive SEC report dated December 21, 2017

ECONOMIC PARAMETERS

Pertinent economic parameters are listed as follows:

a) The effective date is December 31, 2017.

b) Operating and capital costs were estimated in 2018 dollars and then escalated as summarized in the Product Price and Market Forecasts section of this report.

c) Economic forecasts were prepared for each property on a before income tax basis. Detailed discounting of future cash flow was performed using a discount factor of 10.0 percent with all values discounted annually to December 31, 2017, on a mid-calendar-year basis.

d) Royalty holidays applicable to existing wells or forecast drilling are included in individual well economics. These credits are itemized within the property reports.

e) Gas processing allowances relating to remaining undepreciated capital bases, were included in individual property economic evaluations.

f) Mineral taxes on freehold interests were included.

g) Field level overhead charges have been included; recovery of overhead expenses has not been included.

h) The Company’s office G&A costs have not been included.

i) Abandonment and reclamation costs for all existing and future wells to which reserves have been assigned have been included at the property level. Costs have been scheduled 5 years after the last year of production for each well. Additional abandonment and reclamation costs associated with pipelines and facilities have not been included in this analysis.

OIL EQUIVALENT OR GAS EQUIVALENT

In this report, quantities of hydrocarbons have been converted to barrels of oil equivalent (boe); or to sales gas equivalent (sge) using factors of 6 Mcf/boe for gas, 1 bbl/boe for all liquids, and 0 boe for sulphur. Users of oil equivalent values are cautioned that while boe based metrics are useful for comparative purposes, they may be misleading when used in isolation.

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LIST OF ABBREVIATIONS

AOF	absolute open flow
bbl	barrels
Bcf	billion cubic feet of gas at standard conditions
BIIP	bitumen initially-in-place
boe	barrel of oil equivalent, in this evaluation determined using 6 Mcf/boe for gas, 1 bbl/boe for all liquids, and 0 boe for sulphur
bopd	barrels of oil per day
Btu	British thermal units
bwpd	barrels of water per day
DSU	drilling spacing unit
GCA	gas cost allowance
GIIP	gas initially-in-place
GOC	gas-oil contact
GOR	gas-oil ratio
GORR	gross overriding royalty
GWC	gas-water contact
Mbbl	thousand barrels
Mboe	thousand boe
Mcf	thousand cubic feet of gas at standard conditions
Mcfe	thousand cubic feet of gas equivalent
Mlt	thousand long tons
M$	thousand dollars
MM$	million dollars
MMbbl	million barrels
MMboe	million boe
MMBtu	million British thermal units
MMcf	million cubic feet of gas at standard conditions
MRL	maximum rate limitation
Mstb	thousand stock tank barrels
MMstb	million stock tank barrels
NGL	natural gas liquids (ethane, propane, butane and condensate)
NPI	net profits interest
OIIP	oil initially-in-place
ORRI	overriding royalty interest
OWC	oil-water contact
P&NG	petroleum and natural gas
PIIP	petroleum initially-in-place
psia	pounds per square inch absolute
psig	pounds per square inch gauge
PVT	pressure-volume-temperature
RLI	reserves life index, calculated by dividing reserves by the forecast of first year production
scf	standard cubic feet
sge	sales gas equivalent – if presented in this evaluation, determined using 1 barrel of oil or natural gas liquid = 6 Mcfe; 0 for sulphur
stb	stock tank barrel
WI	working interest
WTI	West Texas Intermediate

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Table 1

GLJ Petroleum Consultants

Crude Oil and Natural Gas Liquids

SEC 2017-Dec-31 Posted (12 Month Avg.)

Effective January 1, 2018

NYMEX WTI Near Month Futures Contract Crude Oil at Cushing, Oklahoma

Brent Blend Crude Oil FOB North Sea

Light, Sweet Crude Oil (40 API, 0.3%S) at Edmonton

Bow River Crude Oil Stream Quality at Hardisty

WCS Crude Oil Stream Quality at Hardisty

Heavy Crude Oil Proxy (12 API) at Hardisty

Light Sour Crude Oil (35 API, 1.2%S) at Cromer

Medium Crude Oil (29 API, 2.0%S) at Cromer

Alberta Natural Gas Liquids (Then Current Dollars)

Inflation %

CADUSD Exchange Rate USD/CAD

Constant 2018$ USD/bbl

Then Current USD/bbl

Then Current USD/bbl

Then Current CAD/bbl

Then Current CAD/bbl

Then Current CAD/bbl

Then Current CAD/bbl

Then Current CAD/bbl

Then Current CAD/bbl

Spec Ethane CAD/bbl

Edmonton Propane CAD/bbl

Edmonton Butane CAD/bbl

Edmonton C5+ Stream Quality CAD/bbl

0.0

0.7690

51.03

51.03

54.07

63.43

51.48

51.09

45.18

62.68

60.55

7.28

28.38

44.70

67.46

Table 2

GLJ Petroleum Consultants

Natural Gas and Sulphur

SEC 2017-Dec-31 Posted (12 Month Avg.)

Effective January 1, 2018

Midwest Price at Chicago

Alliance Transfer Pool Spot

Alberta Plant Gate

NYMEX Henry Hub Near Month Contract

AECO/NIT Spot

Spot

Saskatchewan Plant Gate

British Columbia

Constant 2018 $ USD/ MMBtu

Then Current USD/MMBtu

Then Current USD/MMBtu

Then Current CAD/ MMBtu

Then Current CAD/ MMBtu

Constant 2018 $ CAD/ MMBtu

Then Current CAD/ MMBtu

ARP CAD/ MMBtu

SaskEnergy CAD/ MMBtu

Spot CAD/ MMBtu

Sumas Spot USD/ MMBtu

Westcoast Station 2 CAD/ MMBtu

Spot Plant Gate CAD/ MMBtu

Sulphur FOB Vancouver USD/lt

Alberta Sulphur at Plant Gate CAD/lt

2.98

2.98

2.86

2.35

2.45

2.09

2.09

2.09

2.19

2.25

2.73

1.44

1.23

85.75

61.51

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Table 3

GLJ Petroleum Consultants

International and Frontier

SEC 2017-Dec-31 Posted (12 Month Avg.)

Effective January 1, 2018

Inflation %	CADUSD Exchange Rate USD/CAD						NYMEX WTI Near Month Futures Contract Crude Oil at Cushing, Oklahoma				Light Louisiana Sweet Crude Oil				Maya Crude Oil				Brent Blend Crude Oil FOB NorthSea				NYMEX Henry Hub Near Month Contract				Algonquin City- Gates				National Balancing Point (UK)
			GBPUSD Exchange Rate USD/GBP		EURUSD Exchange Rate USD/EUR		Then Current USD/bbl		Then Current CAD/bbl		Then Current USD/bbl		Then Current CAD/bbl		Then Current USD/bbl		Then Current CAD/bbl		Then Current USD/bbl		Then Current CAD/bbl		Then Current USD/ MMBtu		Then Current CAD/ MMBtu		Then Current USD/ MMBtu		Then Current CAD/ MMBtu		Then Current USD/ MMBtu		Then Current CAD/ MMBtu
0.0		0.7690		1.2560		1.1260		51.03		66.36		54.18		70.46		47.06		61.20		54.07		70.31		2.98		3.88		3.06		3.98		6.50		8.45

Table 4

GLJ Petroleum Consultants

US Liquids and Natural Gas

SEC 2017-Dec-31 Posted (12 Month Avg.)

Effective January 1, 2018

US Natural Gas Liquids (Then Current Dollars)															US Natural Gas (Then Current Dollars)
Conway							Mont Belvieu								Rockies Natural Gas USD/MMBtu		Algonquin City-Gates Natural Gas USD/MMBtu
80%-20% E/P Mix USD/bbl	Propane USD/bbl		Butane USD/bbl		Condensate USD/bbl		Ethane USD/bbl		Propane USD/bbl		Butane USD/bbl		Condensate USD/bbl
7.71		32.03		38.50		48.63		10.57		34.04		38.29		49.86		2.72		3.06

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