KELT EXPLORATION LTD.
ANNUAL INFORMATION FORM
For the Year Ended
December 31, 2021
March 10, 2022
TABLE OF CONTENTS
SELECTED DEFINITIONS ......................................................................................................................................... 1
PRESENTATION OF INFORMATION ....................................................................................................................... 2
ABBREVIATIONS AND CONVERSIONS ................................................................................................................. 2
FORWARD-LOOKING STATEMENTS AND INFORMATION ............................................................................... 3
CORPORATE STRUCTURE ....................................................................................................................................... 5
GENERAL DEVELOPMENT OF THE BUSINESS .................................................................................................... 5
DESCRIPTION OF THE BUSINESS ........................................................................................................................... 8
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION ........................................ 10
PRICING ASSUMPTIONS......................................................................................................................................... 13
RECONCILIATION OF CHANGES IN RESERVES AND FUTURE NET REVENUE ......................................... 14
ADDITIONAL INFORMATION RELATING TO RESERVES DATA.................................................................... 15
RISK FACTORS ......................................................................................................................................................... 22
INDUSTRY CONDITIONS ........................................................................................................................................ 37
DIVIDEND POLICY .............................................................................................................................................. ......52
DESCRIPTION OF SHARE CAPITAL ................................................................................................................. ......52
MARKET FOR SECURITIES .................................................................................................................................. ....53
PRIOR SALES .......................................................................................................................................................... ....53
ESCROWED SECURITIES ...................................................................................................................................... ....54
DIRECTORS AND OFFICERS ................................................................................................................................ ....54
AUDIT COMMITTEE .............................................................................................................................................. ....56
LEGAL PROCEEDINGS AND REGULATORY ACTIONS .................................................................................. ...56
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS ......................................... ...56
TRANSFER AGENT AND REGISTRAR ................................................................................................................ ...57
MATERIAL CONTRACTS ...................................................................................................................................... ...57
INTERESTS OF EXPERTS ...................................................................................................................................... ...57
ADDITIONAL INFORMATION.............................................................................................................................. ...57
APPENDICES
Appendix A – Form 51-101F2 – Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor
Appendix B – Form 51-101F3 – Report of Management and Directors on Oil and Gas Disclosure
Appendix C – Definitions Used for Reserves Categories
Appendix D – Form 52-110F1 – Audit Committee Information Required in an AIF
SELECTED DEFINITIONS
In this Annual Information Form, the following terms have the meanings set forth below, unless otherwise indicated.
Additional terms relating to reserves and other oil and gas information have the meanings set forth in Appendix C –
Definitions Used for Reserves Categories.
“ABCA” means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended, including the regulations
promulgated thereunder.
“Annual Information Form” means this annual information form of the Corporation dated March 10, 2022.
“Arrangement” means the plan of arrangement as more particularly described under the heading “General
Development of the Business – History of Kelt – General History”.
“Board of Directors” means the board of directors of Kelt.
“Celtic” means Celtic Exploration Ltd.
“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of
Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy and Petroleum
(Petroleum Society), as amended from time to time.
“Common Shares” means the common shares of Kelt.
“COVID-19” means the novel coronavirus which was declared a global pandemic by the World Health Organization
on March 11, 2020;
“Credit Facility” has the meaning set forth under the heading “General Development of the Business – 2021”.
“Debentures” has the meaning set forth under the heading “General Development of the Business – History of Kelt –
2020”.
“IFRS” means International Financial Reporting Standards.
“Inga Assets” has the meaning set forth under the heading “General Development of the Business – 2020”.
“Kelt” or the “Corporation” means Kelt Exploration Ltd.
“NI 51-101” means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.
“NI 51-102” means National Instrument 51-102 – Continuous Disclosure Obligations.
“NI 52-110” means National Instrument 52-110 – Audit Committees.
“Options” means the options to acquire Common Shares.
“Preferred Shares” means the preferred shares of Kelt.
“RSUs” means the restricted share units of Kelt.
“Second Amended and Restated Credit Agreement” has the meaning set forth under the heading “General
Development of the Business – History of Kelt – 2019”.
“Sproule” means Sproule Associates Limited, independent petroleum engineers of Calgary, Alberta.
“Sproule Report” means the report prepared by Sproule dated February 8, 2022 and effective as of December 31,
2021 entitled “Evaluation of the P&NG Reserves of Kelt Exploration Ltd. (As of December 31, 2021)”.
“TSX” means the Toronto Stock Exchange.
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PRESENTATION OF INFORMATION
The information contained in this Annual Information Form is presented as at December 31, 2021 except where
otherwise noted. In this Annual Information Form, unless otherwise noted, all dollar amounts are expressed in
Canadian dollars.
ABBREVIATIONS AND CONVERSIONS
Abbreviations
The following abbreviations have the meanings set forth below.
AECO
API
bbl/d
bbls
BOE
Alberta Energy Company interconnect with Nova system, the Canadian benchmark for natural gas pricing
American Petroleum Institute
Barrels per day
Barrels
Barrel of oil equivalent of natural gas and crude oil on the basis of one bbl of crude oil for 6 Mcf of natural
gas
Barrel of oil equivalent per day
Long tons
Long tons per day
Thousands of dollars
Cubic metres
Thousand barrels
Thousand barrels of oil equivalent
Thousand cubic feet
Thousand cubic feet per day
BOE/d
Lt
Lt/d
M$
m3
Mbbl
MBOE
Mcf
Mcf/d
MMBtu One million British thermal units
MMcf Million cubic feet
MMcf/d Million cubic feet per day
NGL
WTI
Natural gas liquids
West Texas Intermediate of Cushing, Oklahoma, the benchmark for crude oil pricing purposes
Non-GAAP and other Financial Measures
Within this Annual Information Form, references are made to terms commonly used in the oil and natural gas industry.
The term “netback” in this Annual Information Form is not a recognized measure under generally accepted accounting
principles in Canada. Kelt uses “netback” or “operating netback” as a key performance indicator and it is used by
Kelt in operational and capital allocation decisions. It is determined by deducting royalties and operating expenses
from petroleum and natural gas revenue. The Company also presents operating netbacks on a per boe basis which
allows management to better analyze performance against prior periods, on a comparable basis, and is a key industry
performance measure of operational efficiency.
Readers are cautioned, however, that this measure should not be construed as an alternative to net earnings or cash
flow from operating activities determined in accordance with generally accepted accounting principles in Canada as
an indication of Kelt’s performance.
See the “Adjusted Funds from Operations” section of Kelt’s Management’s Discussion and Analysis as at and for the
year ended December 31, 2021 which provides a reconciliation of the operating netback from P&NG sales, which is
a GAAP measure.
“Capital expenditures, before A&D” “capital expenditures net of A&D” and “capital expenditures, after property
acquisitions” are measures the Company uses to monitor its investment in exploration and evaluation, investment in
property plant and equipment, and investment in acquisition activities. The most directly comparable GAAP measure
is Cash provided by (used in) financing activities, and is calculated as follows:
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(CA$ thousands, except as otherwise indicated)
Cash provided by (used in) financing activities
Change in non-cash investing working capital
Capital expenditures, net of A&D
Property dispositions (1)
Capital expenditures, after property acquisitions
Three months ended December 31
2021
74,421
(7,303)
67,118
(57)
67,061
2020
17,208
7,262
24,470
102
24,572
2021
191,540
21,971
213,511
9,048
222,559
Year ended
December 31
2020
(326,606)
(27,351)
(353,957)
508,389
154,432
(1) Property dispositions for the year ended December 31, 2021 includes $200k of non-cash consideration. Property dispositions for the year ended
December 31, 2020 includes $2,343k of non-cash consideration.
Conversions
The following table sets forth certain standard conversions from Standard Imperial Units to the International System
of Units (or metric units).
To Convert From
Mcf
m3
Bbls
m3
Feet
Metres
Miles
Kilometres
Acres
Hectares
Gigajoules
MMBtu
Caution Respecting BOE
To
m3
Cubic feet
m3
Bbls
Metres
Feet
Kilometres
Miles
Hectares
Acres
MMBtu
Gigajoules
Multiply By
28.174
35.494
0.159
6.293
0.305
3.281
1.609
0.621
0.405
2.500 (Alberta and British Columbia)
0.950
1.0526
In this Annual Information Form, the abbreviation BOE means a barrel of oil equivalent on the basis of 1 BOE to
6 Mcf of natural gas when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation.
A BOE conversion ratio of 6 Mcf to 1 BOE is based on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the wellhead.
FORWARD-LOOKING STATEMENTS AND INFORMATION
This Annual Information Form contains forward-looking statements and forward-looking information (collectively,
“forward-looking statements”). These statements relate to future events or Kelt’s future performance. All statements
other than statements of historical fact may be forward-looking statements. In some cases, forward-looking statements
can be identified by terminology such as “may”, “will”, “should”, “expect”, “plan”, “anticipate”, “believe”,
“estimate”, “predict”, “potential”, “continue”, or the negative of these terms or other comparable terminology. These
statements are only predictions. Actual events or results may differ materially. In addition, this Annual Information
Form may contain forward-looking statements attributed to third party industry sources. Although the Corporation
believes these publications and reports can be reasonably relied-on, it has not independently verified any of the data
or other statistical information contained therein, nor has it ascertained or validated the underlying economic or other
assumptions. Undue reliance should not be placed on these forward-looking statements, as there can be no assurance
that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking
information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific,
that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will
not occur. Forward-looking statements in this Annual Information Form include, but are not limited to, statements
with respect to:
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capital expenditure programs and future capital requirements and the timing and method of
financing thereof;
the Corporation’s exploration and development activities;
drilling inventory, drilling plans and timing of drilling, re-completion and tie-in of wells;
the production from Kelt’s assets;
results of various projects of Kelt;
estimated abandonment and reclamation costs;
the Corporation’s access to adequate pipeline capacity and third-party infrastructure;
growth expectations within Kelt;
the performance and characteristics of Kelt’s oil and natural gas properties;
the quantity and quality of the Corporation’s oil and natural gas reserves;
timing of development of undeveloped reserves;
the tax horizon and taxability of Kelt;
supply and demand for oil, natural gas liquids and natural gas;
Kelt’s acquisition strategy, the criteria to be considered in connection therewith and the benefits to
be derived therefrom;
realization of the anticipated benefits of acquisitions and dispositions;
commodity prices and costs;
the dividend policy of Kelt;
Kelt’s hedging activities;
industry conditions pertaining to the oil and gas industry; and
treatment under government regulation and taxation regimes.
With respect to forward-looking statements contained in this Annual Information Form, Kelt has made assumptions
regarding, among other things:
future crude oil, natural gas and NGL prices and commodity prices generally;
future exchange rates;
the ability of Kelt to obtain qualified staff, drilling and related equipment in a timely and cost-
efficient manner to meet its needs;
the timing and amount of capital expenditures;
future operating costs and future cash flow;
future capital expenditures to be made by the Corporation;
future sources of funding for the Corporation’s capital program;
the Corporation’s future debt levels;
oil, natural gas and NGL production levels;
prevailing weather conditions;
general economic and financial market conditions;
government regulation in the areas of taxation, royalty rates and environmental protection;
production of new and existing wells and the timing of new wells coming on-stream;
the performance characteristics of oil and natural gas properties;
the size of Kelt’s oil, natural gas and NGL reserves and the recoverability of its reserves;
the ability to raise capital and to continually add to reserves through exploration and development;
the success of exploration and development activities;
the Corporation’s ability to market production of oil and natural gas successfully to customers;
the applicability of technologies for recovery and production of the Corporation’s reserves;
the geography of the areas in which the Corporation is conducting exploration and development
activities; and
the impact of competition on the Corporation.
Although Kelt believes that the expectations reflected in the forward-looking statements are reasonable, there can be
no assurance that such expectations will prove to be correct. Kelt cannot guarantee future results, levels of activity,
performance, or achievements. Moreover, neither Kelt nor any other person assumes responsibility for the outcome
of the forward-looking statements. There are many risks and other factors beyond Kelt’s control which could cause
results to differ materially from those expressed in the forward-looking statements contained in this Annual
Information Form. These risks and other factors include, but are not limited to:
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ongoing impacts of COVID-19, including but not limited to impacts on field activity levels, demand
for and supply of hydrocarbons, commodity prices and health and safety considerations and
restrictions which may impact the ability of the Corporation to carry on business as planned;
general economic and political conditions in Canada, the United States and globally;
industry conditions, including fluctuations in the price of oil, natural gas liquids and natural gas;
liabilities inherent in oil and natural gas operations;
environmental and climate change risks;
availability of equity and debt financing;
governmental regulation of the oil and gas industry, including environmental regulation;
fluctuation in foreign exchange or interest rates;
geological, technical, drilling and processing problems and other difficulties in producing reserves;
unanticipated operating events which can reduce production or cause production to be shut in or
delayed;
failure to realize anticipated benefits of acquisitions and dispositions;
failure to obtain industry partner and other third party consents and approvals, when required;
stock market volatility and market valuations;
competition for, among other things, capital, acquisitions or reserves, undeveloped land and skilled
personnel;
competition for and inability to retain drilling rigs and other services;
right to surface access;
the need to obtain required approvals from regulatory authorities; and
the other factors considered under “Risk Factors” in this Annual Information Form.
These factors should not be considered as exhaustive. Statements relating to “reserves” or “resources” are by their
nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions
that the resources and reserves described can be profitably produced in the future.
The above summary of assumptions and risks related to forward-looking information has been provided in this Annual
Information Form in order to provide readers with a more complete perspective on Kelt’s future operations. Readers
are cautioned that this information may not be appropriate for other purposes.
The forward-looking statements contained in this Annual Information Form are expressly qualified by this
cautionary statement. Kelt is not under any duty to update or revise any of the forward-looking statements
except as expressly required by applicable securities laws.
Name, Address and Incorporation
CORPORATE STRUCTURE
The Corporation was incorporated under the ABCA on October 11, 2012 as “1705972 Alberta Ltd.” On October 19,
2012, Articles of Amendment were filed to change the name of the company to “Kelt Exploration Ltd.” On November
7, 2012, Kelt filed Articles of Amendment to remove the private company restrictions on share transfers and to amend
the minimum number of directors to three (3).
Kelt Exploration (LNG) Ltd. (formerly, Artek Exploration Ltd.), a corporation incorporated under the ABCA, is a
wholly-owned subsidiary of the Corporation. Kelt does not have any other subsidiaries.
The head office of Kelt is located at Suite 300, 311 – 6th Avenue S.W., Calgary, Alberta T2P 3H2 and its registered
office is located at Suite 1900, 520 – 3rd Avenue S.W., Calgary, Alberta T2P 0R3.
GENERAL DEVELOPMENT OF THE BUSINESS
Overview
Kelt is an oil and gas company based in Calgary, Alberta, focused on the exploration, development and
production of crude oil and natural gas resources, primarily in west central Alberta and northeastern British Columbia.
Kelt’s land holdings are located in three operating divisions, namely: (a) Pouce Coupe/Progress, Alberta - Kelt’s
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Alberta development division; (b) Wembley/Pipestone, Alberta – Kelt’s Alberta exploration division; and (c)
Oak/Flatrock, British Columbia – Kelt’s B.C. exploration division. Kelt also has a number of minor properties not
included in the three operating divisions. See “Description of the Business” and “Statement of Reserves Data and
Other Oil and Gas Information”.
COVID-19
On January 30, 2020 the World Health Organization (“WHO”) declared a Public Health Emergency of International
Concern for a novel coronavirus strain which was later named COVID-19. By March 2020, the WHO declared the
COVID-19 a pandemic with governments around the world imposing significant public health measures in order to
reduce its spread. The COVID-19 pandemic resulted in an unprecedented global crude oil demand reduction in 2020
which in turn significantly lowered the average global benchmark crude oil price in 2020. Positive vaccine
development along with temporary production curtailments from OPEC+ and non-OPEC nations, resulted in a
recovery in crude oil prices in the in 2021, with the average global benchmark crude oil price rebounding above pre
COVID-19 prices in the second half of 2021. This volatility in crude oil and natural gas prices in 2020 and 2021 has
had a significant impact on Kelt’s revenue from commodity sales. For further details on these risks, refer to “Risk
Factors” in this Annual Information Form.
Kelt continues to monitor current market conditions resulting from the COVID-19 pandemic. The Corporation’s
highest priority remains the health and safety of its employees, partners and the communities where it operates. Kelt
continues to maintain measures that have been put in place to protect the well-being of these stakeholders and is proud
of the dedication of its workforce to maintain safe operations and business continuity in a challenging environment
Given the uncertainty of the extent and duration of the COVID-19 pandemic and its impacts on the economy and the
energy business more broadly, as well as the timeline of the transition to a fully reopened economy, the future impact
on the Corporation’s business and its financial results and condition remains uncertain.
History of Kelt
General History
Kelt was incorporated on October 11, 2012 for the purposes of participating in the plan of arrangement under section
193 of the ABCA involving the Corporation, Celtic, ExxonMobil Canada Ltd., ExxonMobil Celtic ULC and the
shareholders and debentureholders of Celtic (the “Arrangement”). The Arrangement was completed on February 26,
2013 pursuant to which, among other things, each shareholder received one-half (1/2) of one Common Share of Kelt
for each common share of Celtic held. In connection with the Arrangement, Celtic assigned and transferred to Kelt
all of Celtic’s right, title, estate and interest in and to certain petroleum, natural gas and related hydrocarbon rights and
related personal property interests. Since the completion of the Arrangement, Kelt has carried on the business of the
exploration for, and the development and production of, oil and natural gas.
On March 1, 2013, the Common Shares commenced trading on the TSX under the stock symbol “KEL”.
2019
On March 29, 2019, Kelt amended and restated its amended and restated syndicated credit agreement, as amended, by
entering into the Second Amended and Restated Credit Agreement (the “Second Amended and Restated Credit
Agreement”) which, among other matters, increased the amount of Kelt’s credit facilities from $250.0 million to
$315.0 million.
On November 7, 2019, Kelt entered into the first amending agreement to the Second Amended and Restated Credit
Agreement to, among other matters, increase the amount of Kelt’s credit facilities from $315.0 million to $350.0
million.
On November 8, 2019, Kelt announced that it had approved an initial capital expenditure budget of $235.0 million for
2020.
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On December 20, 2019 Kelt completed a non-brokered private placement of 3,450,000 Common Shares, on a “flow-
through” share basis in respect of Canadian development expenses, at a price of $5.05 per share. Proceeds from the
foregoing private placement were used for drilling and completion expenditures incurred in 2019 and 2020.
2020
On February 20, 2020, Kelt announced that it had amended its 2020 capital expenditures budget from $235.0 million
to $225.0 million, in part to reflect the planned 2020 expenditures that were brought forward and incurred in 2019.
On March 17, 2020, Kelt announced that the board had approved a reduction in capital expenditures for 2020, reducing
its capital expenditure budget to $145.0 million.
On August 21, 2020, Kelt completed the sale of its oil and gas assets in its Inga/Fireweed/Stoddart Division (the “Inga
Assets”), located in British Columbia effective as of July 1, 2020. Cash proceeds were $510.0 million, prior to closing
adjustments. In addition, the purchaser assumed $28.8 million of financing liabilities and $1.1 million of lease and
other liabilities.
Concurrently with the completion of the sale of its Inga Assets, Kelt paid out all amounts outstanding under the $350.0
million revolving committed term credit facility under the Second Amended and Restated Credit Agreement, as
amended. For business continuity purposes, Kelt entered into a new $20.0 million demand revolving credit facility
with a Canadian chartered bank.
In addition, on August 21, 2020, Kelt announced the Board had approved $20.0 million in capital expenditures for the
second half of 2020, excluding capital expenditures that are part of the closing adjustments with respect to the sale of
the Inga Assets.
On August 21, 2020, Kelt also mailed a redemption notice to the registered holders of its 5.00% convertible unsecured
subordinated debentures due May 31, 2021 (the “Debentures”) and to Computershare Trust Company of Canada, as
debenture trustee. Pursuant to the redemption notice, Kelt redeemed the $89,910,000 of outstanding principal amount
of the Debentures plus all accrued but unpaid interest up to but excluding the date of redemption of October 3, 2020.
In connection with the redemption of the Debentures, the Debentures were delisted from the Toronto Stock Exchange.
On November 10, 2020, Kelt announced that the Board had approved a capital expenditure budget of $90.0 million
for 2021 and that Louise K. Lee had been appointed Corporate Secretary and Douglas J. Errico had been appointed as
Senior Vice President, Land and Corporate Development as of November 9, 2020. Mr. Errico has been Vice President,
Land of Kelt since October 22, 2012.
2021
On January 7, 2021, Kelt announced the release of its inaugural ESG Report, dated January 7, 2021, as part of its
ongoing commitment to health and safety, responsible and sustainable resource development, good governance
practices and community engagement. The ESG Report can be viewed on Kelt’s website at www.keltexploration.com.
On May 24, 2021, Kelt announced that the Board had approved an increase to its capital expenditure program for 2021
from $120.0 million to $150.0 million
On June 30, 2021, Kelt announced the appointment of Janet E. Vellutini as a director of the Corporation effective July
1, 2021 and the retirement of Robert J. Dales as a director of the Corporation effective July 1, 2021.
On November 10, 2021, Kelt announced that the Board had approved an increase to its capital expenditure program
for 2021 from $175.0 million to between $190.0 and $200.0 million and that the Corporation had entered into a new
credit facility with a borrowing capacity of $100.0 million (the “Credit Facility”). Kelt also announced the Board
had approved an initial capital expenditure budget between the range of $200.0 million and $210.0 million for 2022.
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Activity During Current Financial Year
On February 17, 2022, Kelt released its second ESG Report as part of its ongoing commitment to health and safety,
responsible and sustainable resource development, good governance practices and community engagement. The ESG
Report can be viewed on Kelt’s website at www.keltexploration.com.
Significant Acquisitions
Kelt has not completed any “significant acquisitions” (as such term is defined in NI 51-102) during the financial year
ended December 31, 2021.
General Description of the Business
DESCRIPTION OF THE BUSINESS
Kelt is an oil and gas company based in Calgary, Alberta, focused on the exploration, development and
production of crude oil and natural gas resources, primarily in west central Alberta and northeastern British Columbia.
Kelt’s land holdings are located in three operating divisions, namely: (a) Pouce Coupe/Progress, Alberta - Kelt’s
Alberta development division; (b) Wembley/Pipestone, Alberta – Kelt’s Alberta exploration division; and (c)
Oak/Flatrock, British Columbia – Kelt’s B.C. exploration division. Kelt also has a number minor properties not
included in the three operating divisions.
Stated Business Objective
The business plan of Kelt is to create sustainable and profitable growth as a participant in the oil and gas industry in
Canada. Kelt seeks to identify and acquire strategic oil and gas properties where it believes further exploitation,
development and exploration opportunities exist. In addition, Kelt has implemented a full cycle exploration program,
resulting in exploration and development drilling based on opportunities generated internally. Kelt may complement
its exploration and development drilling program with acquisitions and dispositions that optimize its asset base.
Kelt pursues exploration plays that have low, medium and high risk and multi-zone hydrocarbon potential and strives
to maintain a balance between exploration, exploitation and development drilling for oil and gas reserves, although
management of Kelt also considers asset and corporate acquisition opportunities that meet its business parameters.
While Kelt believes that it has the skills and resources necessary to achieve its stated objectives, participation in the
exploration for and development of oil and gas has a number of inherent risks. See “Risk Factors” in this Annual
Information Form.
Marketing
Kelt markets its crude oil, natural gas and NGLs production to credit-worthy third party companies at market prices.
Crude oil contracts are generally month to month and cancellable on 30 days’ notice, NGL contracts are generally for
a period of up to one year and natural gas transactions vary in duration, generally for one year or less. The Corporation
has a combination of firm and interruptible pipeline transportation service to deliver its crude oil, natural gas, and
NGLs production to markets that range in length from 1-8 years.
Cyclical and Seasonal Nature of Industry
Kelt’s operational results and financial condition are dependent on the prices received for oil and natural gas
production. Oil and natural gas prices have fluctuated widely during recent years. Global benchmark crude oil price
averaged $68.03 US$/bbl WTI and AECO 5A gas reference prices averaged $3.62 Cdn$/MMBtu during 2021.
Kelt’s natural gas marketing portfolio may be adjusted with an objective to maximizing its natural gas netbacks and
to diversify the Corporation’s price risk away from a single market. In 2021, Kelt’s natural gas sales were split
between the following markets: Dawn (28%), Chicago (5%) and AECO/Station 2 (67%).
The Corporation may enter into fixed price contracts and derivative financial instruments for commodity prices in
order to secure future cash flows or to protect a desired level of capital spending See “Risk Factors – Hedging” in this
Annual Information Form.
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Such prices are determined by supply and demand factors, including weather and general economic conditions, as
well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse
effect on the financial condition of Kelt. See “Risk Factors – Prices, Markets and Marketing of Crude Oil and Natural
Gas” in this Annual Information Form.
The production of oil and natural gas is dependent on access to areas where development of reserves is to be conducted.
Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances. See “Risk
Factors – Seasonality” in this Annual Information Form.
Employees
As at the date of this Annual Information Form, Kelt has 50 full-time employees and 4 part-time employees located
at its head office. In addition, the Corporation has 20 full time employees located at various field operational sites.
To continue with the development of its assets, Kelt may require additional experienced employees and third-party
consultants and contractors. See “Risk Factors – Reliance on Key Personnel” in this Annual Information Form.
Specialized Skill and Knowledge
Kelt believes its success is dependent on the performance of its management and key employees, many of whom have
specialized knowledge and skills relating to oil and gas operations. Kelt believes that it has adequate personnel with
the specialized skills required to successfully carry out its operations. See “Risk Factors – Reliance on Key Personnel”
in this Annual Information Form.
Competitive Conditions
The oil and gas industry is highly competitive. Kelt actively competes for reserve acquisitions, exploration leases,
licences and concessions and skilled industry personnel with a substantial number of other oil and gas entities, many
of which have significantly greater financial resources, staff and facilities than Kelt. Kelt’s competitors include
integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual
producers and operators. Certain of Kelt’s customers and potential customers may themselves explore for oil and
natural gas and the results of such exploration efforts could affect Kelt’s ability to sell or supply oil or gas to these
customers in the future. Kelt’s ability to successfully bid on and acquire additional property rights, to discover
reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers
is dependent upon developing and maintaining close working relationships with its future industry partners and joint
operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly
competitive environment. Competitive factors in the distribution and marketing of oil and natural gas include price
and methods and reliability of delivery and storage. Competition may also be presented by alternate fuel sources. See
“Risk Factors – Competition” in this Annual Information Form.
Environmental Protection
The oil and gas industry is subject to environmental regulations pursuant to applicable legislation. Such legislation
provides for restrictions and prohibitions on release or emission of various substances produced in association with
certain oil and gas industry operations, and requires that well and facility sites be abandoned and reclaimed to the
satisfaction of environmental authorities. Kelt maintains an insurance program consistent with industry practice to
protect against losses due to accidental destruction of assets, well blowouts, pollution and other operating accidents
or disruptions. Kelt has established operational and emergency response procedures and safety and environmental
programs to reduce potential loss exposure. No assurance can be given that the application of environmental laws to
the business and operations of Kelt will not result in a curtailment of production or a material increase in the costs of
production, development or exploration activities or otherwise adversely affect Kelt’s financial condition, results of
operations or prospects. See “Risk Factors – Environmental Risks” and “Industry Conditions – Environmental
Regulation” in this Annual Information Form.
Social and Environmental Policies
Kelt is committed to meeting industry standards in each jurisdiction in which it operates with respect to human rights,
environment, health and safety policies. Management, employees and contractors are governed by and required to
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comply with Kelt’s environment, health and safety policy as well as all applicable federal, provincial and municipal
legislation and regulations.
Kelt has established roles and responsibilities to facilitate effective management of its environment, health and safety
policy throughout the organization. It is the primary responsibility of the managers, supervisors and other senior field
staff of Kelt to oversee safe work practices and ensure that rules, regulations, policies and procedures are being
followed.
Kelt released its second ESG Report dated February 17, 2022 as part of its ongoing commitment to disclose to
stakeholders its policies and achievements in health and safety, sustainable resource development, governance
practices and community engagement. The ESG Report highlights many of the Corporation’s achievements,
including: completed projects that are expected to reduce the Corporation’s methane emissions by 1,000 tonnes
compared to 2020 levels; a reduction in carbon emissions by switching the fuel source for drilling and frac operations
to displace carbon intensive diesel; a reduction in recordable and lost time injuries for the 5th consecutive year;
completed a renewal of it Board of Directors resulting in female representation increasing to 33%; the amendment of
the Health, Safety and Environment Committee’s mandate to include oversight over climate risks as well as ESG
reporting; and the construction of an ultra low GHG emission facility and well sites at Oak, BC.
Bankruptcy and Similar Procedures
There has been no bankruptcy, receivership or similar proceedings against Kelt, or any voluntary bankruptcy,
receivership or similar proceedings by Kelt.
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Petroleum and Natural Gas Reserves
Sproule, independent petroleum engineers of Calgary, Alberta, prepared the Sproule Report evaluating and auditing
the proved and probable crude oil, natural gas and NGL reserves attributable to Kelt’s interest in 100% of its properties
and the present value of estimated future cash flow from such reserves, based on forecast price and cost assumptions.
All of Kelt’s reserves are in Canada, and, specifically, in Alberta and British Columbia. The reserves information was
prepared and is presented in accordance with the requirements of NI 51-101.
In preparing the Sproule Report, Sproule obtained information from Kelt, 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, future operating plans and estimated
abandonment and reclamation costs for Kelt’s dedicated facilities. Other engineering, geological or economic data
required to conduct the evaluation and audit and upon which the Sproule Report is based, was obtained from public
records, other operators and from Sproule’s non-confidential files. The extent and character of ownership and the
accuracy of all factual data supplied for the independent evaluation, from all sources, was accepted by Sproule as
represented.
Disclosure of Reserves Data
It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair
market value of the reserves. There are numerous uncertainties inherent in estimating quantities of crude oil, NGL and
natural gas reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow
information set forth in this Annual Information Form are estimates only. The recovery and reserve estimates of the
crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated
reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the
estimates provided herein. In general, estimates of economically recoverable crude oil and natural gas reserves and
the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical
production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures,
marketability of crude oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies
and future operating costs, all of which may vary materially from actual results. For those reasons, among others,
estimates of the economically recoverable crude oil, natural gas and NGL reserves attributable to any particular group
of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated
with reserves may vary and such variations may be material. The actual production, revenues, taxes and development
-10-
and operating expenditures with respect to the reserves associated with Kelt’s assets may vary from the information
presented herein and such variations could be material. See “Risk Factors” in this Annual Information Form.
The following tables, based on the Sproule Report, show the estimated share of Kelt’s oil, natural gas and NGL
reserves in its properties and the present value of estimated future net revenue for these reserves, after provision for
Alberta gas cost allowance, using forecast price and cost assumptions. All evaluations and audits of the present
worth of estimated future net revenue in the Sproule Report are stated after provision for estimated future
capital expenditures, both before and after income taxes but prior to indirect costs or equipment salvage values
and do not necessarily represent the fair market value of the reserves.
Throughout the following summary tables differences may arise due to rounding.
In accordance with the requirements of NI 51-101, attached hereto are the following appendices:
Appendix A:
Appendix B:
Report on Reserves Data by Independent Qualified Reserves Evaluator or
Auditor in Form 51-101F2 containing certain information estimated using
forecast prices and costs based on December 31, 2021 pricing assumptions
Report of Management and Directors on Oil and Gas Disclosure in
Form 51-101F3
Definitions used for reserve categories in the Sproule Report are attached as Appendix C hereto.
The following table summarizes Kelt’s oil and gas reserves as of December 31, 2021 based on forecast price and cost
assumptions.
SUMMARY OF OIL AND GAS RESERVES
as of December 31, 2021
FORECAST PRICES AND COSTS
RESERVES
LIGHT CRUDE OIL
AND MEDIUM CRUDE
OIL
CONVENTIONAL
NATURAL GAS(1)
CONVENTIONAL
NATURAL GAS(2)
NATURAL GAS
LIQUIDS
TOTAL BOE
Gross
(Mbbl)
Net
(Mbbl)
Gross
(MMcf)
Net
(MMcf)
Gross
(MMcf)
Net
(MMcf)
Gross
(Mbbl)
Net
(Mbbl)
Gross
(Mbbl)
Net
(Mbbl)
4,908
205
9,069
14,182
10,065
4,074
48,291
44,481
134,164
121,425
194
1,104
1,035
5,779
7,429
11,697
7,916
68,279
117,674
79,845
63,336
108,852
73,657
234,441
374,384
324,044
5,350
214,365
341,140
288,849
8,537
731
28,631
37,899
42,678
6,895
43,854
623
2,083
23,958
31,476
34,773
88,155
134,092
120,057
38,620
1,881
77,671
118,172
103,107
24,247
19,613
197,519
182,509
698,428
629,989
80,577
66,249
254,149
221,279
RESERVES CATEGORY
PROVED
Developed Producing
Developed Non-
Producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS
PROBABLE
Notes:
(1)
(2)
Conventional natural gas (solution gas) includes all gas produced in association with light, medium and heavy crude oil and tight oil.
Associated and non-associated gas.
The following tables summarize the undiscounted value and the present value, discounted at 5%, 10%, 15% and 20%,
of Kelt’s estimated future net revenue based on forecast price and cost assumptions as of December 31, 2021.
-11-
RESERVES
CATEGORY
PROVED
Developed
Producing
Developed
Non-
Producing
SUMMARY OF NET PRESENT VALUES OF
FUTURE NET REVENUE
as of December 31, 2021(1)
FORECAST PRICES AND COSTS
BEFORE INCOME TAXES
DISCOUNTED AT (%/year)
AFTER INCOME TAXES
DISCOUNTED AT (%/year)
UNIT
VALUE
BEFORE
INCOME
TAX
DISCOUNT
-ED AT
10%/year
0
(M$)
5
(M$)
10
(M$)
15
(M$)
20
(M$)
0
(M$)
5
(M$)
10
(M$)
15
(M$)
20
(M$)
$/BOE
575,517
573,185
519,977
471,919
433,335
575,517
573,185
519,977
471,919
433,335
13.46
16.74
7.39
9.52
9.87
38,103
34,509
31,495
29,020
26,977
38,103
34,509
31,495
29,020
26,977
Undeveloped
1,228,472
816,255
574,104
421,223
318,559
950,986
625,510
434,411
314,157
233,716
TOTAL
PROVED
1,839,092
1,423,949
1,125,576
922,162
778,871
1,561,607
1,233,203
985,883
815,096
694,028
PROBABLE
2,085,924
1,401,028
1,018,070
781,812
624,401
1,598,543
1,062,521
763,106
579,483
458,080
TOTAL
PROVED
PLUS
PROBABLE
Note:
(1)
3,925,016
2,824,977
2,143,646
1,703,974
1,403,272
3,160,149
2,295,725
1,748,989
1,394,579
1,152,109
9.69
Values reflect abandonment and reclamation costs for all existing wells assigned reserves and for all future locations assigned reserves
in the Sproule Report as well as abandonment and reclamation costs for dedicated facilities required to produce the assigned reserves,
in the aggregate amount of $214.9 million (undiscounted) for total proved reserves and $244.9 million (undiscounted) for total proved
plus probable reserves.
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2021
FORECAST PRICES AND COSTS
RESERVES
CATEGORY
REVENUE
(M$)
ROYALTIES
(M$)
OPERATING
COSTS
(M$)
DEVELOP-
MENT
COSTS
(M$)
ABANDON-
MENT AND
RECLAMA-
TION
COSTS
(M$)
FUTURE
NET
REVENUE
BEFORE
INCOME
TAXES
(M$)
INCOME
TAXES
(M$)
FUTURE
NET
REVENUE
AFTER
INCOME
TAXES
(M$)
Proved
Reserves
Proved Plus
Probable
Reserves
5,242,240
687,513
1,746,389
754,337
214,909
1,839,092
277,486
1,561,607
10,145,145
1,467,329
3,087,024
1,420,857
244,919
3,925,016
764,866
3,160,149
-12-
FUTURE NET REVENUE
BY PRODUCTION TYPE
as of December 31, 2021
FORECAST PRICES AND COSTS
RESERVES
CATEGORY
Proved Reserves
Proved Plus
Probable Reserves
PRODUCTION TYPE
Light and Medium Crude Oil (including solution gas and associated by-
products)
Conventional Natural Gas (including associated by-products) (1)
Other Items
Total
Light and Medium Crude Oil (including solution gas and associated by-
products)
Conventional Natural Gas (including associated by-products) (1)
Other Items
Total
Note:
(1)
Includes corporate capital gas cost allowance.
Forecast Prices and Costs - December 31, 2021
PRICING ASSUMPTIONS
FUTURE NET
REVENUE
BEFORE
INCOME TAXES
(discounted at
10%/Year)
(M$)
UNIT VALUE
BEFORE INCOME
TAXES
(discounted at
10%/Year)
($/BOE)
405,701
722,291
-2,417
1,125,576
731,782
1,414,280
-2,417
2,143,646
11.26
8.79
-
12.16
8.78
-
Sproule employed the following pricing, exchange rate and inflation rate assumptions in estimating Kelt’s reserves
data using forecast prices and costs as of December 31, 2021.
Year
Historical
2017
2018
2019
2020
2021
Forecast
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Thereafter
FORECAST PRICES USED IN PREPARING RESERVES DATA
Sproule Associates Limited
Price Forecast
Effective December 31, 2021
Light Oil
Heavy & Medium Oil
Natural Gas Liquids
WTI Cushing
Oklahoma
($US/Bbl)
Canadian
Light Sweet
Crude
40° API
($Cdn/Bbl)
Western
Canada Select
20.5° API
($Cdn/Bbl)
Hardisty
Bow River
24.9° API
($Cdn/Bbl)
Edmonton
Propane
($Cdn/Bbl)
Edmonton
Butane
($Cdn/Bbl)
Edmonton
Pentanes
Plus
($Cdn/Bbl)
50.56
53.11
59.10
35.92
69.04
28.77
27.00
17.16
16.31
43.39
76.76
72.64
69.77
71.17
72.59
74.05
75.53
77.04
78.58
80.15
81.75
Escalation rate of 2.0% thereafter
38.64
36.05
34.68
35.37
36.08
36.80
37.53
38.28
39.05
39.83
40.63
44.11
33.65
23.71
21.87
51.64
54.75
50.75
49.30
50.29
51.29
52.32
53.36
54.43
55.52
56.63
57.76
67.21
79.31
71.39
49.85
85.88
91.25
87.50
85.00
86.70
88.43
90.20
92.01
93.85
95.72
97.64
99.59
50.95
64.77
57.02
39.40
67.91
73.00
70.00
68.00
69.36
70.75
72.16
73.61
75.08
76.58
78.11
79.67
61.85
68.49
68.87
45.39
80.31
86.25
82.40
79.80
81.39
83.02
84.68
86.38
88.10
89.87
91.66
93.50
50.24
52.34
58.77
35.59
68.73
75.63
71.56
68.74
70.12
71.52
72.95
74.41
75.90
77.42
78.96
80.54
-13-
FORECAST PRICES USED IN PREPARING RESERVES DATA
Sproule Associates Limited
Price Forecast
Effective December 31, 2021
Henry Hub
Price
($US/MMBtu)
Natural Gas
Alberta
AECO-C
Spot
($Cdn/MMBtu)
Alliance
Chicago Spot
($Cdn/MMBtu)
Operating
Cost
Inflation
Rate
(%/Yr)
Exchange
Rate
($US/$Cdn)
3.02
3.07
2.53
2.13
3.72
4.00
3.50
3.25
3.32
3.38
3.45
3.52
3.59
3.66
3.73
3.81
2.19
1.53
1.80
2.24
3.64
3.88
3.36
3.02
3.08
3.14
3.21
3.27
3.34
3.40
3.47
3.54
3.69
3.92
3.20
2.50
5.74
1.7
2.4
(0.7)
(5.0)
3.3
4.85
4.22
3.91
3.98
4.06
4.15
4.23
4.31
4.40
4.49
4.58
-
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
Escalation rate of 2.0% thereafter
0.77
0.77
0.75
0.75
0.80
0.80
0.80
0.80
0.80
0.80
0.80
0.80
0.80
0.80
0.80
0.80
Year
Historical
2017
2018
2019
2020
2021
Forecast
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Thereafter
Kelt’s weighted average selling prices before financial instruments for the year ended December 31, 2021 were
$81.30/Bbl for oil, $40.03/Bbl for NGLs and $4.35/Mcf for natural gas, before derivative financial instruments. See
“Additional Information Relating to Reserves Data – Netback History” in this Annual Information Form.
RECONCILIATION OF CHANGES IN RESERVES AND FUTURE NET REVENUE
Reserves Reconciliation
The following table sets forth a reconciliation of the total gross (before calculation of royalties and before
consideration of the Corporation’s royalty interests) proved, probable and proved plus probable reserves as at
December 31, 2021 based on forecast price and cost assumptions.
LIGHT CRUDE OIL AND
MEDIUM CRUDE OIL(1)
Gross
Proved
(Mbbl)
Gross
Probable
(Mbbl)
15,450
-
538
542
-
-
(709)
3
12,718
-
357
102
-
186
(948)
-
70
(1,713)
(2,349)
-
Gross
Proved
Plus
Probable
(Mbbl)
28,168
-
895
644
-
186
(1,657)
3
(2,279)
(1,713)
CONVENTIONAL GAS(1)
NATURAL GAS LIQUIDS(1)
TOTAL EQUIVALENT
Gross
Proved
(MMcf)
Gross
Probable
(MMcf)
348,315
-
70,887
17,524
-
-
(4,983)
2,246
86,775
(28,706)
270,660
-
66,941
33,856
-
764
(5,313)
(1,646)
38,628
-
Gross
Proved
Plus
Probable
(MMcf)
618,975
-
137,828
51,380
-
764
(10,296)
600
125,403
(28,706)
Gross
Proved
(Mbbl)
Gross
Probable
(Mbbl)
22,453
-
8,570
1,100
-
-
(86)
426
6,587
(1,151)
24,998
-
11,464
3,254
-
13
(89)
(372)
3,410
-
Gross
Proved
Plus
Probable
(Mbbl)
47,451
-
20,034
4,354
-
13
(175)
54
9,997
(1,151)
Gross
Proved
(MMcf)
Gross
Probable
(MMcf)
95,956
-
20,924
4,563
-
-
(1,626)
803
21,120
(7,648)
82,826
-
22,976
8,998
-
326
(1,922)
(646)
7,499
-
Gross
Proved
Plus
Probable
(MMcf)
178,782
-
43,900
13,561
-
326
(3,548)
157
28,619
(7,648)
14,182
10,065
24,247
492,058
403,890
895,948
37,899
42,678
80,577
134,092
120,057
254,149
FACTORS
December 31,
2020
Discoveries
Extensions
Infill Drilling
Improved
Recovery
Acquisitions
Dispositions
Economic Factors
Technical
Revisions(2)
Production
December 31,
2021
Notes:
(1)
(2)
Gross Reserves means the Corporation’s working interest reserves before calculation of royalties, and before consideration of the
Corporation’s royalty interests.
Technical Revisions also include changes in reserves associated with operating costs, capital costs and commodity price offsets. Lower
operating expenses resulted in positive technical revisions throughout all of the Corporation’s operating divisions. The improved
performance of existing producers and the associated increases to offsetting locations resulted in positive technical revisions in the
Wembley operating division across all products. Additionally, the Pouce Coupe West Montney natural gas wells’ continued
-14-
(3)
outperformance resulted in positive technical revisions in the Pouce/Progress operating division conventional gas reserves and natural
gas liquids reserves.
Proved component of category change probable undeveloped reserves to proved reserves have been included in the Extensions or Infill
Drilling categories.
ADDITIONAL INFORMATION RELATING TO RESERVES DATA
Undeveloped Reserves
Undeveloped reserves are attributed by Sproule in accordance with standards and procedures contained in the COGE
Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and
are expected to be recovered from known accumulations where a significant expenditure is required to render them
capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than
proved reserves and are expected to be recovered from known accumulations where a significant expenditure is
required to render them capable of production. Proved and probable undeveloped reserves have been assigned in
accordance with engineering and geological practices as defined under NI 51-101. In general, undeveloped reserves
associated with Kelt’s assets are planned to be developed over the next 5 years for both proved and proved and
probable reserves.
There are a number of factors that could result in delayed or cancelled development, including the following: (i)
changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical
conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone
developments (for instance, a prospective formation completion may be delayed until the initial completion formation
is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize
capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather
conditions and regulatory approvals). For more information, see “Risk Factors” in this Annual Information Form.
The following tables sets forth the proved undeveloped reserves and probable undeveloped reserves, by product type,
first attributed as reserves for the following financial periods and first attributed to Kelt’s assets for the year ended
December 31, 2021.
Proved Undeveloped Reserves
LIGHT CRUDE OIL AND
MEDIUM CRUDE OIL
CONVENTIONAL
NATURAL GAS(2)
NATURAL GAS
LIQUIDS
First
Attributed
(Mbbl)
2,446.6
1,356.6
275.8
Cumulative
at Year
End(1)
(Mbbl)
7,728.0
9,936.5
9,069.3
First
Attributed
(MMcf)
159,430
11,629
59,776
Cumulative
at Year
End(1)
(MMcf)
549,833
225,424
302,720
First
Attributed
(Mbbl)
30,866.9
2,334.4
8,194.9
Cumulative
at Year
End(1)
(Mbbl)
71,516.5
16,630.2
28,631.1
TOTAL EQUIVALENT
First
Attributed
(MBOE)
89,885.1
5,629.3
18,433.4
Cumulative
at Year
End(1)
(MBOE)
170,883.3
64,137.3
88,153.8
Year/Period
December 31, 2019
December 31, 2020
December 31, 2021
Notes:
(1)
(2)
Cumulative at year end is cumulative of previous year/period plus first attributed, less developed during the year/period.
Natural gas volumes include solution gas, associated and non-associated gas.
Probable Undeveloped Reserves
LIGHT CRUDE OIL AND
MEDIUM CRUDE OIL
CONVENTIONAL
NATURAL GAS(2)
NATURAL GAS
LIQUIDS
First
Attributed
(Mbbl)
1,838.0
1,913.0
820.3
Cumulative
at Year
End(1)
(Mbbl)
9,567.4
11,074.1
8,461.4
First
Attributed
(MMcf)
302,330
28,446
110,405
Cumulative
at Year
End(1)
(MMcf)
690,753
233,602
345,795
First
Attributed
(Mbbl)
56,654.5
5,426.2
15,598
Cumulative
at Year
End(1)
(Mbbl)
96,723.3
23,175.4
39,872.4
TOTAL EQUIVALENT
First
Attributed
(MBOE)
108,880.7
12,080.1
34,819.1
Cumulative
at Year
End(1)
(MBOE)
221,416.2
73,183.3
105,966.4
Year/Period
December 31, 2019
December 31, 2020
December 31, 2021
Notes:
(1)
(2)
Cumulative at year end is cumulative of previous year/period plus first attributed, less developed during the year/period.
Natural gas volumes include solution gas, associated and non-associated gas.
-15-
Sproule has assigned 88,153.8 MBOE of proved undeveloped reserves in the Sproule Report under forecast prices and
costs, together with approximately $751.0 million of associated undiscounted future capital expenditures. Proven
undeveloped capital spending in the first two forecast years of the Sproule Report accounts for approximately $294.6
million or 39%, of the total forecast. The remaining proven undeveloped reserves are expected to be developed within
5 years based on the Corporation’s current development plans.
Sproule has assigned 105,966.4 MBOE of probable undeveloped reserves and has allocated additional future
development capital of approximately $665.5 million to all probable undeveloped reserves with 23% scheduled for
the first two years. The remaining probable undeveloped reserves are expected to be developed within 6 years based
on the Corporation’s current development plans.
The Corporation has a large inventory of development opportunities and its capital spending is prioritized to optimize
development plans and achieve strategic goals for the Corporation. The pace of development is influenced by many
factors including oil and natural gas prices, prevailing economic conditions and risks and the outcome of yearly drilling
and reservoir evaluations. The Corporation’s undeveloped reserves represent a large resource development which in
its very nature would require several years to optimize capital allocation, facilities and surface access issues. All of
the Corporation’s undeveloped locations are forecast within timeframes recommended in the COGE Handbook for
resource development being five years for proved undeveloped reserves and six years for probable undeveloped
reserves.
Significant Factors or Uncertainties
The process of estimating reserves requires decisions based on available geological, geophysical, engineering and
economic data. These estimates may change substantially as additional data from ongoing development activities and
production performance becomes available and as economic conditions impacting oil and gas prices and costs change.
The reserve estimates contained herein are based on current production forecasts, commodity prices and economic
conditions. Kelt’s reserves are evaluated by Sproule, an independent engineering firm.
Estimates made are reviewed and revised, either upward or downward, as warranted by new information. Revisions
are often required due to changes in well performance, commodity prices, economic conditions and governmental
restrictions. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation
is an inferential science. Kelt’s actual production, revenues, taxes, development and operating expenditures with
respect to its reserves may vary from such estimates, and such variances could be material. See “Risk Factors –
Reserves Estimates” in this Annual Information Form.
Future Development Costs
The following table sets forth development costs deducted in the estimation of the future net revenue attributable to
the reserve categories noted below, using forecast costs.
Year
2022
2023
2024
2025
2026
Remaining Years
Total Undiscounted
Undiscounted Forecast Costs
Proved
Reserves
(M$)
147,975
150,025
148,198
149,185
158,955
-
754,338
Proved Plus
Probable
Reserves
(M$)
206,736
247,158
296,486
295,123
295,033
80,322
1,420,858
The future development costs for both the proved and proved plus probable scenarios are expected to be funded with
internally generated cash flow estimates based on the assumptions contained in the Sproule Report. On an annual
basis, future capital expenditures may differ depending on management’s current development plans which are
dependent on many factors including current commodity prices and access to capital. For 2022, the Corporation has
established a $250 million capital program to fund its exploration and development activities which is in excess of
both the proved and proved plus probable future development costs. The 2022 capital expenditure budget includes
expenditures for land, infrastructure, and exploration or delineation wells that are not contained in the reserve report.
-16-
There can be no guarantee that funds will be available or that the Board of Directors will allocate funding to develop
all of the reserves attributable in the Sproule Report. Failure to develop those reserves could have a negative impact
on Kelt’s future cash flow. The Corporation has not approved a capital program beyond 2022.
Kelt expects to fund the development costs of these reserves through a combination of the funds available from its
Credit Facility, internally generated cash flow and the issuance of new equity and/or debt where and when it believes
appropriate. The Corporation’s capital program does not include any new acquisition opportunities, which would
likely be financed through debt or equity financings, if necessary.
The interest or other costs of external funding are not included in the reserves and future net revenue estimates set
forth above and would reduce the reserves and future net revenue to some degree depending upon the funding sources
utilized. Kelt does not anticipate that interest or other funding costs would make further development of any of Kelt’s
assets uneconomic.
See “Risk Factors – Substantial Capital Requirements; Liquidity” and “– Reserve Estimates” in this Annual
Information Form.
Other Oil and Gas Information
The following is a description of the Corporation’s principal oil and gas properties, and a description of the
Corporation’s major plants, facilities and installations.
Oil and Gas Properties
Pouce Coupe/Progress
As at the date hereof, the Corporation has interests in in 142,828 gross (87,881 net) acres of land in this area which is
located approximately 70 kilometres north of Grande Prairie, Alberta. At Pouce Coupe/Progress, the Corporation has
a 20.256% working interest in the 140 MMcf/d Progress gas plant located at 1-1-078-10W6M and a 100% working
interest in a compression facility located at 6-33-77-11-W6M. At Pouce/Progress, the Corporation has targeted several
different geologic formations including Montney light oil, Montney and Doig natural gas and Charlie Lake and
Halfway light oil.
Wembley/Pipestone
As at the date hereof, the Corporation has interests in 144,970 gross (126,735 net) acres of land in this area which is
located approximately 10 kilometres north of Grande Prairie, Alberta. At Wembley/Pipestone, the Corporation has
an oil battery at 01-14-072-08W6M with a capacity of 3,500 bbl/d of oil and 20 MMcf/d of natural gas. The
Corporation’s natural gas production is processed at third party facilities, including 30 MMcf/d of processing capacity
at a deep cut gas processing plant at Pipestone. At Wembley/Pipestone, the Corporation is primarily targeting light
oil and condensate rich natural gas in the Montney formation.
Oak/Flatrock
As at the date hereof, the Corporation has interests in 196,333 gross (195,629 net) acres of land in this area which is
located approximately 30 kilometres north east of Fort St. John, British Columbia. In the fourth quarter of 2021, Kelt
commenced operations at its newly constructed Oak 6-35 gas compression and oil battery facility. Ten newly drilled
and completed Montney wells and one older producing Upper Montney well were connected to the Oak 6-35 facility
and brought on production at various times during the month of November 2021.
Oil and Gas Wells
The following table sets forth the number and status of wells as at December 31, 2021 in which Kelt has an interest.
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PRODUCING
Location
Alberta
British Columbia
TOTAL
Oil
Gross(1)
219
1
220
Net(2)
141.6
1.0
142.6
Gross
Natural Gas
Net
117.6
18.3
135.9
216
20
236
NON-PRODUCING
Oil
Natural Gas
Gross
Net
Gross
170
-
170
98.2
-
98.2
357
43
400
Net
182.3
24.1
206.4
SERVICE
WELLS
Gross
Net
61
1
62
22.2
1.0
23.2
Notes:
(1)
(2)
“Gross” wells means the number of wells in which Kelt has a working interest or a royalty interest that may be convertible to a working
interest.
“Net” wells means the aggregate number of wells obtained by multiplying each gross well by Kelt’s percentage working interest therein.
Properties with no Attributed Reserves
The following table sets forth the gross and net acres of unproved properties held by Kelt as at December 31, 2021
and the net area of unproved property for which Kelt expects its rights to explore, develop and exploit to expire during
the next year.
LOCATION
Alberta
British Columbia
TOTAL
UNPROVED PROPERTIES - UNDEVELOPED LAND
(acres)
Gross(1)
252,303
205,843
458,146
Net(2) Net Area to Expire by December 31 2022
11,691
2,640
14,331
180,359
191,955
372,314
Notes:
(1)
(2)
“Gross Acres” are the total acres in which Kelt has or had an interest.
“Net Acres” is the aggregate of the total acres in which Kelt has or had an interest multiplied by Kelt’s working interest percentage held
therein.
There are no costs or work commitments associated with Kelt’s non-producing properties except for annual lease
rental payments.
Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves
There are no significant economic factors and uncertainties which affect the anticipated development or production
activities on certain of the Corporation’s properties with no attributed reserves.
Forward Contracts
Kelt’s operational results and financial condition are dependent upon the prices received for oil, natural gas and NGL
production. Oil, natural gas and NGL prices have fluctuated widely in recent years. Such prices are primarily
determined by economic and political factors. Supply and demand factors, as well as weather and conditions in other
oil and natural gas regions of the world also impact prices. Any upward or downward movement in oil, natural gas
and NGL prices could have an effect on Kelt’s financial condition.
Kelt may use certain financial instruments to hedge its exposure to commodity price fluctuations on a portion of its
crude oil and natural gas production. These hedging activities could expose Kelt to losses or gains. See “Risk Factors
– Hedging” in this Annual Information Form and see Kelt’s annual financial statements as at, and for the year ended
December 31, 2021 (note 12).
Additional Information Concerning Abandonment and Reclamation Costs
Kelt estimates the total cost of future abandonment and reclamation for its existing wells, including their associated
production facilities and infrastructure, and the expected timing of the costs to be incurred in future periods. The
Corporation has a process for estimating these costs, which considers past experience, applicable current regulations,
technology and industry standards, actual and anticipated costs, the type and depth of the well (or the nature and size
of the facility), and the geographic location. Kelt expects to incur abandonment and reclamation costs on 1,088 gross
(600.3 net) wells, comprising currently producing, non-producing and service wells. As at December 31, 2021, the
Corporation has estimated its share of the total abandonment and reclamation costs for its existing wells and facilities
-18-
to be $115.1 million undiscounted (approximately $28.5 million discounted at 10%), of which Kelt expects to pay
approximately $10.8 million over the next three financial years.
The Sproule Report in 2021 included the Corporation’s full estimated undiscounted future abandonment and
reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development
activity associated with the reserves.
Tax Horizon
At the end of 2021, Kelt had approximately $774.2 million of tax pools and losses available. It is expected, based
upon current legislation, and estimates of future taxable income and capital expenditures, that no cash income taxes
are to be paid by Kelt for the next three years. A higher level of capital expenditures than those currently contemplated
for 2022, or further additional acquisitions, could further extend the estimated tax horizon, however higher benchmark
commodity prices than those forecasted could reduce the estimated tax horizon.
Income Taxes
Kelt files all required income tax returns and believes that it is in full compliance with the provisions of the Income
Tax Act (Canada) and all other applicable provincial tax legislation. However, such returns are subject to reassessment
by the applicable taxation authority. In the event of a successful reassessment of Kelt, whether by re-characterization
of exploration and development expenditures or otherwise, such reassessment may have an impact on current and
future taxes payable.
Income tax laws relating to the oil and natural gas industry, such as the treatment of resource taxation or dividends,
may in the future be changed or interpreted in a manner that adversely affects Kelt. Furthermore, tax authorities having
jurisdiction over Kelt may disagree with how Kelt calculates its income for tax purposes or could change
administrative practices to the Corporation’s detriment.
Costs Incurred
The following table summarizes Kelt’s corporate and property acquisition costs, exploration costs and development
costs (before property dispositions) incurred during the year ended December 31, 2021. The amounts reported as
unproved acquisition costs and exploration costs are consistent with capital expenditures classified as exploration and
evaluation assets under IFRS. The amounts reported as proved acquisition costs and development costs are consistent
with capital expenditures classified as property, plant and equipment under IFRS.
Acquisitions and Capital Expenditures
Nature of cost
Exploration Costs
Development Costs
Corporate Costs
Capital expenditures, before acquisitions
and dispositions(1)
Property Acquisition Costs
Proved
Unproved
Corporate Acquisition Costs
Proved
Unproved
Capital expenditures, after property
acquisitions (1)
Amount (M$)
2.0
219.2
1.1
222.3
-
-
-
0.2
222.5
Note:
(1)
See the non-GAAP and Other Financial Measures section of this Annual Information Form
-19-
Exploration and Development Activities
The following table sets forth the results of exploration and development activities on Kelt’s assets during the year
ended December 31, 2021:
Wells(1)
Development
Gas
Oil
Service
Exploratory
Gas
Total
Gross
Net
13
8
2
-
23
13.0
7.7
2.0
-
22.7
Note:
(2)
Based on Lahee Classification System.
During 2022, Kelt expects to drill wells in all of its core operating divisions, targeting liquids-rich natural gas at
Oak/Flatrock in British Columbia and natural gas and light oil in Wembley/Pipestone and Pouce/Progress in Alberta.
Production Estimates
The following table discloses, by product type, the volume of working interest share of production estimated for Kelt’s
assets before the deduction of royalties for the first year for gross proved reserves and gross probable reserves (2022)
as reported in the Sproule Report effective December 31, 2021, based on forecast prices and costs.
Corporation
Total Proved
Total Proved Plus
Probable
Light Crude Oil and
Medium Crude Oil (Bbl/d)
3,163
4,475
Conventional
Natural Gas
(Mcf/d)
113,744
142,200
Natural Gas Liquids
(Bbl/d)
Combined (BOE/d)
8,830
12,210
30,950
40,385
The Pouce Coupe/Progress property and the Wembley/Pipestone property each account for 20% or more of the
estimated production set forth in the immediately preceding tables. The following tables disclose by product type the
volume of working interest share of production estimated for each of the properties before the deduction of royalties
for the first year for gross proved reserves and gross probable reserves as reported in the Sproule Report effective
December 31, 2021, based on forecast prices and costs.
The estimated average daily volume of production for the first year for each the Pouce Coupe/Progress property, the
Wembley/Pipestone property, and the Oak/Flatrock property as reported in the Sproule Report is as follows:
Pouce Coupe/Progress
Total Proved
Total Proved Plus Probable
Wembley/Pipestone
Total Proved
Total Proved Plus Probable
Oak/Flatrock
Total Proved
Total Proved Plus Probable
Light Crude Oil and
Medium Crude Oil
(Bbl/d)
Conventional
Natural Gas
(Mcf/d)
Natural Gas
Liquids
(Bbl/d)
Combined
(BOE/d)
1,924
2,915
1,152
1,468
9
9
54,623
66,294
32,260
44,330
18,891
23,316
1,089
1,307
6,326
9,190
1,353
1,649
12,117
15,271
12,854
18,046
4,511
5,544
-20-
Production History
The following table summarizes Kelt’s average daily production before deduction of royalties, for the periods
indicated:
Product
Light & Medium Crude Oil (Bbl/d)
NGLs (Bbl/d)
Conventional Natural Gas (Mcf/d)(1)
Total (BOE/d)
Note:
(1) Sulphur volumes included in conventional natural gas.
Netback History
Year
Q4
4,692
3,154
78,846
20,987
6,624
3,255
95,616
25,815
2021
Q3
4,485
3,004
72,789
19,621
Q2
Q1
3,660
2,932
78,001
19,592
3,972
3,429
68,752
18,860
The following table sets forth information respecting average net product prices received, royalties paid, production
expenses and operating netbacks received by the Corporation in respect of the Corporation’s production of crude oil,
NGLs and natural gas for the periods indicated.
Category
Selling prices(1), before financial instruments:
Year
Q4
2021
Q3
Q2
Q1
Oil ($/Bbl)(2)
NGLs ($/Bbl)(3)
Gas ($/Mcf)(4)
Average ($/BOE)
Selling prices(1), after financial instruments:
Oil ($/Bbl)(2)
NGLs ($/Bbl)(3)
Gas ($/Mcf)(4)
Average ($/BOE)
Royalties ($/BOE)(5)
Transportation and selling expenses:
Oil ($/Bbl)
NGLs ($/Bbl)
Gas ($/Mcf)
Average ($/BOE)
Production expenses(6) ($/BOE)
Operating netbacks(7) ($/BOE)
81.30
40.03
4.35
40.52
76.29
40.03
4.08
38.38
3.58
3.75
0.39
0.66
3.38
9.13
91.43
50.03
5.46
50.01
90.96
50.03
4.79
47.39
4.17
4.20
0.56
0.59
3.31
9.91
82.35
42.45
4.32
41.37
75.83
42.45
3.90
38.33
4.40
3.58
0.48
0.73
3.59
9.24
76.33
32.94
3.49
33.09
66.37
32.94
3.56
31.49
2.80
3.29
0.27
0.68
3.36
7.65
67.47
34.28
3.77
34.17
61.05
34.28
3.84
33.07
2.70
3.59
0.24
0.67
3.25
9.45
22.29
30.00
21.10
17.68
17.67
Notes:
(1)
(2)
(3)
(4)
(5)
(6)
(7)
“Selling prices” include total revenue (before royalties) by product category, net of the cost of purchases, are expressed as an average
per unit of production.
“Oil” includes crude oil and field condensate.
“NGLs” include pentane, butane, propane, and ethane.
“Gas” includes natural gas and sulphur.
Royalties, which are net of Crown Cost Allowances (as defined below), are expressed as an average per BOE. Crown Cost Allowances
includes Gas Cost Allowance (“GCA”) in Alberta and Producer Cost of Service (“PCOS”) in British Columbia. Given the
Corporation’s gas wells often have significant associated field condensate and NGL production, the total amount of GCA and PCOS
credits received relates to field condensate and NGL royalties, as well as gas royalties.
Production expenses include, but are not limited to, mineral lease and surface lease rentals, property taxes and expenses related to the
operation and maintenance of wells, production facilities and gathering systems. Due to the nature of Kelt’s petroleum and natural gas
assets being comprised of oil wells with associated gas production, and of gas wells with significant associated field condensate and
NGL production, actual production expenses by product type are not readily determinable. As a result, an allocation of production
expenses by product type is not meaningful.
“Operating Netback” is calculated by deducting the royalties, production expenses and transportation expenses from petroleum and
natural gas revenue, net of the cost of purchases and after realized gains and losses on associated financial instruments. The Corporation
also refers to operating netback expressed per unit of production.
-21-
Production Volume by Field
The following table discloses for each important field, and in total, Kelt’s production volumes for the financial year
ended December 31, 2021 for each product type.
Light Crude Oil
and Medium
Crude Oil
(Bbl/d)
Natural Gas
Liquids
(Bbl/d)
Conventional
Natural Gas
(Mcf/d) (1)
Combined
(BOE/d)
%
320
2,115
2,172
85
4,692
103
757
2,234
60
3,154
4,468
45,584
20,133
8,661
78,846
1,168
10,469
7,761
1,589
20,987
6
50
37
7
100
Field
Oak/Flatrock
Pouce Coupe/Progress
Wembley/Pipestone
Other
TOTAL
Note:
(1)
Sulphur volumes have been converted to oil equivalence at 0.6 Lt per BOE.
RISK FACTORS
The business of exploring for, developing and producing oil and natural gas reserves is inherently risky. The following
information is a summary only of certain risk factors relating to the Corporation and should be read in conjunction
with the detailed information appearing elsewhere in this Annual Information Form. Prospective investors should
carefully consider the risk factors set out below and consider all other information contained in this Annual
Information Form and in the Corporation’s other public filings before making an investment decision. The risks set
out below are not an exhaustive list, nor should be taken as a complete summary or description of all the risks
associated with the Corporation’s business and the oil and natural gas business generally.
COVID-19
Pandemics, epidemics or outbreaks of an infectious disease in Canada or worldwide could have an adverse impact on
the Corporation’s business, including changes to the way the Corporation and its counterparties operate, and on the
Corporation’s financial results and condition. At the onset of the COVID-19 pandemic, governments and regulatory
bodies in affected areas imposed a number of measures designed to contain the COVID-19 pandemic, including
widespread business closures, social distancing protocols, travel restrictions, quarantines, curfews and restrictions on
gatherings and events. While a number of containment measures have been and continue to be gradually eased or
lifted across some regions, additional safety precautions and operating protocols aimed at containing the spread of
COVID-19 have been and continue to be instituted in line with guidance of public health authorities. In addition,
COVID-19 variants have led to the imposition of containment measures to varying degrees globally. These
containment measures in 2021 impacted the global economic activity, including the ability to move towards recovery
of the global economy and such measures also contribute to the decreased demand for hydrocarbons, increased market
volatility and continued changes to the macroeconomic environment. Although the containment measures are being
eased globally, new COVID-19 variants may have an adverse impact on the Corporation’s business strategies and
initiatives, resulting in negative effects to the Corporation’s financial results, including the increase of counterparty,
market and operational risks.
The Corporation’s business, financial condition, results of operations, cash flows, reputation, access to capital, cost of
borrowing, access to liquidity, and/or business plans may, in particular, and without limitation, be adversely impacted
as a result of the pandemic, new COVID-19 variants, and/or decline in commodity prices as a result of: the shut-down
of facilities or the delay or suspension of work on major capital projects due to workforce disruption or labour
shortages caused by workers becoming infected with COVID-19, or government or health authority mandated
restrictions on travel by workers or closure of facilities or worksites; suppliers and third-party vendors experiencing
similar workforce disruption or being ordered to cease operations; reduced cash flows resulting in less funds from
operations being available to fund capital expenditure budgets; reduced commodity prices resulting in a reduction in
the volumes and value of reserves; crude oil storage constraints resulting in the curtailment or shutting in of
production; counterparties being unable to fulfill their contractual obligations on a timely basis or at all; the inability
to deliver products to customers or otherwise get products to market caused by border restrictions, road or port closures
-22-
or pipeline shut-ins, including as a result of pipeline companies suffering workforce disruptions or otherwise being
unable to continue to operate; and the ability to obtain additional capital including, but not limited to, debt and equity
financing being adversely impacted as a result of unpredictable financial markets, commodity prices and/or a change
in market fundamentals.
Kelt continues to monitor current market conditions resulting from the COVID-19 pandemic. The Corporation’s
highest priority remains the health and safety of its employees, partners and the communities where it operates. Kelt
continues to maintain measures that have been put in place to protect the well-being of these stakeholders and is proud
of the dedication of its workforce to maintain safe operations and business continuity in a challenging environment
Given the uncertainty of the extent and duration of the COVID-19 pandemic, as well as the potential for new COVID-
19 variants emerging, the impacts on the economy and the energy business more broadly, as well as the timeline of
the transition to a fully reopened economy, the future impact on the Corporation’s business and its financial results
and condition remains uncertain.
Carbon Pricing Risk
Taxes on carbon emissions affect the demand for oil and natural gas, the Corporation’s operating expenses and may
impair the Corporation’s ability to compete. The majority of countries across the globe have agreed to reduce their
carbon emissions in accordance with the Paris Agreement. In Canada, the federal government implemented legislation
aimed at incentivizing the use of alternative fuels and in turn reducing carbon emissions. The federal system applies
in provinces and territories that request it to be implemented or are without their own system that meets federal
standards. The federal regime was subject to a number of court challenges by Alberta, Saskatchewan and Ontario. The
final decision from the Supreme Court of Canada is expected to be delivered sometime in 2021. See “Industry
Conditions – Environmental Regulation”. Any taxes placed on carbon emissions may have the effect of decreasing
the demand for oil and natural gas products and at the same time, increasing the Corporation’s operating expenses,
each of which may have a material adverse effect on its profitability and financial condition. Further, the imposition
of carbon taxes puts the Corporation at a disadvantage with its counterparts who operate in jurisdictions where there
are less costly carbon regulations.
Climate Change
Climate change policy is evolving at regional, national and international levels, and political and economic events
may significantly affect the scope and timing of climate change measures that are ultimately put in place. The federal
and certain provincial governments have implemented legislation aimed at incentivizing the use of alternatives fuels
and in turn reducing carbon emissions. The taxes placed on carbon emissions may have the effect of decreasing the
demand for oil and natural gas products and at the same time, increasing the Corporation’s operating expenses, each
of which may have a material adverse effect on the Corporation’s profitability and financial condition. Further, the
imposition of carbon taxes puts the Corporation at a disadvantage with the Corporation’s counterparts who operate in
jurisdictions where there are less costly carbon regulations.
Adverse impacts to the Corporation’s business as a result of comprehensive carbon emission legislation or regulation
applied to the Corporation’s business in Alberta or any jurisdiction in which the Corporation operates, may include,
but are not limited to: (i) increased compliance costs; (ii) permitting delays; (iii) substantial costs to generate or
purchase emission credits or allowances adding costs to the products the Corporation produces; and (iv) reduced
demand for crude oil and certain refined products. Emission allowances or offset credits may not be available for
acquisition or may not be available on an economic basis. Required emission reductions may not be technically or
economically feasible to implement, in whole or in part, and failure to meet such emission reduction requirements or
other compliance mechanisms may have a material adverse effect on the Corporation’s business resulting in, among
other things, fines, permitting delays, penalties and the suspensions of operations. See “Industry Conditions – Climate
Change Regulation” in this Annual Information Form.
In addition to climate policy risk, the industry faces physical risks attributable to a changing climate. Climate change
is expected to increase the frequency of severe weather conditions, including high winds, heavy rainfall, extreme
temperatures, flooding and wildfires, which may result in damage to the Corporation’s assets, disruptions in operations
or transportation interruptions which may lead to increased capital expenditures or reduced revenues.
-23-
Environmental Risks
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental
regulation pursuant to a variety of international conventions and federal, provincial and municipal laws and
regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills,
releases or emissions of various substances produced in association with oil and gas operations. The legislation also
requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable
regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a
manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased
capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water
may give rise to liabilities to foreign governments and third parties and may require Kelt to incur costs to remedy such
discharge. See “Industry Conditions – Environmental Regulation” in this Annual Information Form. No assurance
can be given that the application of environmental laws to the business and operations of Kelt will not result in a
curtailment of production or a material increase in the costs of production, development or exploration activities or
otherwise adversely affect Kelt’s financial condition, results of operations or prospects.
Indigenous Claims
Opposition by Indigenous groups to conduct the Corporation’s operations, development or exploratory activities in
any of the jurisdictions in which the Corporation conducts business may negatively impact the Corporation in terms
of public perception, diversion of management’s time and resources, legal and other advisory expenses, and could
adversely impact the Corporation’s progress and ability to explore and develop properties.
Some Indigenous groups have established or asserted Indigenous treaty, title and rights to portions of Canada.
Although there are no Indigenous and treaty rights claims on lands where the Corporation operates, no certainty exists
that any lands currently unaffected by claims brought by Indigenous groups will remain unaffected by future claims.
Such claims, if successful, could have a material adverse impact on the Corporation’s operations or pace of growth.
The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating
actions that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain circumstances,
accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the
circumstances and is often the subject of ongoing litigation. The fulfillment of the duty to consult Indigenous people
and any associated accommodations may adversely affect the Corporation’s ability to, or increase the timeline to,
obtain or renew, permits, leases, licences and other approvals, or to meet the terms and conditions of those approvals.
Kelt is monitoring the impact of the recent Supreme Court of British Columbia judgement in Yahey v British Columbia
(the “Blueberry Decision”) with respect to a claim brought forth by the Blueberry River First Nation (the “BRFN”)
against the province of British Columbia regarding the cumulative impact of industrial development within the BRFN
treaty claim area. The Blueberry Decision found that the Province of British Columbia breached the Treaty 8 rights
of the BRFN by allowing extensive industrial development on the BRFN’s traditional territory without first assessing
the cumulative impacts of this development on the ability of the members of the BRFN to exercise their Treaty 8 rights
to hunt, fish, and trap on their traditional territory. The Blueberry Decision calls for the province of British Columbia
to pause some development in the BRFN traditional area pending the results of an investigation into the cumulative
impacts of industrial development in the BRFN’s traditional territory. The Blueberry Decision gave six months for
the Government of British Columbia and the BRFN to negotiate changes to the regulatory regime that recognizes and
respects treaty rights.
On October 7, 2021, the Government of British Columbia and the BRFN announced they reached a first step in the
initial agreement in developing land management processes on the BRFN traditional territory. As part of this
agreement, a number of forestry and oil and gas projects, which were permitted or authorized prior to the Blueberry
Decision, would continue to proceed. The announcement also states that the Province of British Columbia and BRFN
are working to finalize an interim approach for reviewing new natural resource activities that balance Treaty 8 rights,
the economy and the environment.
The Corporation does not currently expect that there will be an impact to Kelt’s 2022 guidance as a result of the
negotiations between the Blueberry and the Government of British Columbia. However any future delays in obtaining
permits in the province of British Columbia in 2022 may result in a re-allocation of capital expenditures from the
province of British Columbia to Alberta.
-24-
Volatility in the Oil and Gas Industry
Market events and conditions, including global oil and natural gas supply and demand, world health emergencies
(including the ongoing COVID-19 pandemic), actions taken by the Organization of the Petroleum Exporting Countries
(“OPEC”) and non-OPEC member countries’ decisions on production growth and space capacity, market volatility
and disruptions, weakening global relationships, conflict between the U.S. and Iran, isolationist and punitive trade
policies, U.S. shale production, sovereign debt levels and political upheavals in various countries including growing
anti-fossil fuel sentiment, have caused significant volatility in commodity prices. In 2020, with the rapid spread of
COVID-19 and additional oil supply, oil prices and global equity markets deteriorated significantly and they remain
under pressure. The extreme supply/demand imbalance caused a reduction in industry spending in 2020. The oil and
natural gas industry rebounded strongly throughout 2021, with oil prices reaching their highest levels in six years. It
is anticipated that the oil and natural gas industry will experience more pressure from investors to take meaningful
strides towards combating climate change in the upcoming years, including diversifying their energy portfolios.
Russia’s recent invasion of Ukraine has led to sanctions being levied against Russia by the international community
and may result in additional sanctions or other international action, any of which may have a destabilizing effect on
commodity prices and global economies more broadly. These events and conditions have been a factor in the volatility
in the valuation of oil and gas companies. These difficulties have been exacerbated in Canada by political and other
actions resulting in uncertainty surrounding regulatory, tax and royalty changes and other environmental regulations.
In addition, the difficulties to get the necessary approvals or other delays to build pipelines and other facilities to
provide better access to markets for the oil and gas industry in western Canada has led to additional uncertainty and
reduced confidence in the oil and gas industry in western Canada. Lower commodity prices may also affect the
volume and value of the Corporation’s reserves especially as certain reserves become uneconomic. In addition, lower
commodity prices have had an effect on, and may continue to have an effect on the Corporation’s cash flow which
could result in a change to the Corporation’s capital expenditure budget. As a result, the Corporation may not be able
to replace its production with additional reserves and both the Corporation’s production and reserves could be reduced
on a year over year basis. Any decrease in value of the Corporation’s reserves may reduce the borrowing base under
the Credit Facility, which, depending on the level of the Corporation’s indebtedness, could result in the Corporation
having to repay a portion of its indebtedness. Given the current market conditions and the lack of confidence in the
Canadian oil and gas industry, the Corporation may have difficulty raising additional funds in the future or if it is able
to do it may be on unfavourable and highly dilutive terms.
Credit Facility
The amount authorized under the Corporation’s credit agreement governing the Credit Facility is dependent on the
borrowing base determined by its lender. The lender uses the Corporation’s reserves, commodity prices, and other
factors, to periodically determine the Corporation’s borrowing base. Lower commodity prices could result in a
reduction to the Corporation’s borrowing base, reducing the funds available to the Corporation under the Credit
Facility. This could result in the requirement to repay a portion, or all, of the Corporation’s indebtedness.
Prices, Markets and Marketing of Crude Oil and Natural Gas
Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors,
all of which are beyond the control of Kelt. World prices for oil and natural gas have fluctuated widely in recent
years. Any material decline in prices will result in a reduction of net production revenue. Oil and natural gas prices
are expected to remain volatile in the near future in response to a variety of factors beyond the Corporation’s control,
including but not limited to: (i) global energy supply, production and policies, including the ability of OPEC to set
and maintain production levels in order to influence prices for oil; (ii) political conditions, instability, hostilities and
epidemics; (iii) global and domestic economic conditions, including currency fluctuations; (iv) the level of consumer
demand, including demand for different qualities and types of crude oil and liquids and the availability and pricing of
alternative fuel sources; (v) the production and storage levels of North American natural gas and crude oil and the
supply and price of imported oil and liquefied natural gas; (vi) weather conditions; (vii) the proximity of reserves and
resources to, and capacity of, transportation facilities and the availability of refining and fractionation capacity; (viii)
the ability, considering regulation and market demand, to export oil and liquefied natural gas and NGLs from North
America; (ix) the effect of world-wide energy conservation and greenhouse gas reduction measures and the price and
availability of alternative fuels; and (x) government regulations, actions by the Government of Alberta including,
without limitation, imposing, amending, or lifting crude oil production curtailments. Certain wells or other projects
may become uneconomic as a result of a decline in world oil prices and natural gas prices, leading to a reduction in
the future volume of Kelt’s oil and gas production. Kelt might also elect not to produce from certain wells at lower
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prices. All these factors could result in a material decrease in Kelt’s future net production revenue, causing a reduction
in its oil and gas acquisition and development activities. In addition, bank borrowings available to Kelt will be in part
determined by the borrowing base of Kelt. A sustained material decline in prices from historical average prices could
reduce Kelt’s future borrowing base, therefore reducing the bank credit available to Kelt, and could require that a
portion of any existing bank debt of Kelt be repaid.
In addition to establishing markets for its oil and natural gas, Kelt must also successfully market its oil and natural gas
to prospective buyers. The marketability and price of oil and natural gas which may be acquired or discovered by
Kelt will be affected by numerous factors beyond its control. Kelt will be affected by the differential between the
price paid by refiners for light quality oil and the grades of oil produced by Kelt. The ability of Kelt to market natural
gas may depend upon its ability to acquire space on pipelines which deliver natural gas to commercial markets. Kelt
will also likely be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and
processing facilities and related to operational problems with such pipelines and facilities and extensive government
regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and
the management of other aspects of the oil and natural gas business. Kelt has limited direct experience in the marketing
of oil and natural gas.
Political Uncertainty
In the last several years, the United States and certain European countries have experienced significant political events
that have cast uncertainty on global financial and economic markets. After the withdrawal of the United States from
the Trans-Pacific Partnership, Canada entered into the CPTPP (as defined herein) along with 10 other countries. The
United States, Canada and Mexico also signed the USMCA (as defined herein) which replaced NAFTA was ratified
on July 1, 2020, see “Industry Conditions – Trade Agreements” in this Annual Information Form. In 2021, the Biden
administration in the U.S. revoked certain permits required for the construction of the Keystone X.L. pipeline, resulting
in the projects cancellation by TC Energy. Future actions taken by the U.S. administration could have a negative
impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation
of Canadian oil and natural gas companies.
In addition to the political disruption in the United States, the impact of the United Kingdom’s exit from the European
Union are slowly emerging and some impacts may not become apparent for some time. Additionally, some European
countries have also experienced the rise of antiestablishment political parties and public protests held against open-
door immigration policies, trade and globalization. To the extent that certain political actions taken in North America,
Europe and elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of
movement it could have an adverse effect on the Corporation’s ability to market its products internationally, increase
costs for goods and services required for third party lessees’ operations, reduce their access to skilled labour and as a
result, negatively impact the Corporation’s business, operations, financial conditions and the market value of the
Common Shares.
A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by
such governments on matters that may impact the oil and natural gas industry including the balance between economic
development and environmental policy. The United Conservative Party government in Alberta is supportive of the
Trans Mountain Pipeline expansion project and, although there has been notable opposition from the government of
British Columbia, the federal Government remains in support of the project. Continued uncertainty and delays have
led to decreased investor confidence, increased capital costs and operational delays for producers and service providers
operating in the jurisdiction.
The federal Liberal Government was re-elected in 2021, but continues to hold a minority position. The ability of the
minority federal government to pass legislation will be subject to whether it is able to come to agreement with, and
garner the support of, the other elected parties, most of whom are opposed to the development of the oil and natural
gas industry. The minority federal government will also be required to rely on the support of the other elected parties
to remain in power, which provides less stability and may lead to an earlier subsequent federal election. Lack of
political consensus, at both the federal and provincial level, continues to create regulatory uncertainty, the effects of
which become apparent on an ongoing basis, particularly with respect to carbon pricing regimes, curtailment of crude
oil production and transportation and export capacity, and may affect the business of participants in the oil and natural
gas industry.
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The oil and natural gas industry has become an increasingly politically polarizing topic in Canada, which has resulted
in a rise in civil disobedience surrounding oil and natural gas development - particularly with respect to infrastructure
projects. Protests, blockades and demonstrations have the potential to delay and disrupt the Corporation’s activities.
See “Industry Conditions – Pipelines”, “– Crude Oil and Bitumen by Rail”, “– Trade Agreements” and “Climate
Change Regulation” in this Annual Information Form.
Exploration, Development and Production Risks
Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful
evaluation may not be able to overcome. There is no assurance that expenditures made on exploration by the
Corporation will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to project the
costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown
formations, the costs associated with encountering various drilling conditions such as over pressured zones and tools
lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic
data and interpretations thereof. The long-term commercial success of the Corporation depends on its ability to find,
acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new
reserves, the Corporation’s existing reserves, and the production from them, will decline over time as the Corporation
produces from such reserves. A future increase in the Corporation’s reserves will depend on both the ability of the
Corporation to explore and develop its existing properties and on its ability to select and acquire suitable producing
properties or prospects. There is no assurance that the Corporation will be able to continue to find satisfactory
properties to acquire or participate in. Moreover, management of the Corporation may determine that current markets,
terms of acquisition, participation or pricing conditions make potential acquisitions or participations uneconomic.
There is also no assurance that the Corporation will discover or acquire further commercial quantities of oil and natural
gas.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells but from wells that are
productive but do not produce sufficient net revenues to return a profit after drilling, completing, operating and other
costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating
costs.
Drilling hazards or environmental damage could greatly increase the cost of operations and various field operating
conditions may adversely affect the production from successful wells. These conditions include, but are not limited
to, delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme
weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.
While diligent well supervision and effective maintenance operations can contribute to maximizing production rates
over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which
can negatively affect revenue and cash flow levels to varying degrees.
Oil and natural gas exploration, development and production operations are subject to all the risks and hazards
typically associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering and spills
or other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural
gas wells, production facilities, other property, the environment and personal injury.
Oil and natural gas production operations are also subject to all the risks typically associated with such operations,
including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water
into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse
effect on the Corporation’s business, financial condition, results of operations and prospects.
As is standard industry practice, the Corporation is not fully insured against all risks, nor are all risks insurable.
Although the Corporation maintains liability insurance in an amount that it considers consistent with industry practice,
liabilities associated with certain risks could exceed policy limits or not be covered. In either event the Corporation
could incur significant costs. See “Risk Factors– Insurance” in this Annual Information Form.
Gathering and Processing Facilities and Pipeline Systems
The Corporation delivers its products through gathering, processing and pipeline systems some of which it does not
own. The amount of oil and natural gas that the Corporation can produce and sell is subject to the accessibility,
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availability, proximity and capacity of these gathering, processing and pipeline systems. The lack of availability of
capacity in any of the gathering, processing and pipeline systems, and in particular the processing facilities, could
result in the Corporation’s inability to realize the full economic potential of its production or in a reduction of the price
offered for the Corporation’s production. Although pipeline expansions are ongoing, the lack of firm pipeline capacity
continues to affect the oil and natural gas industry and limit the ability to produce and to market oil and natural gas
production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems also continues to affect the
ability to export oil and natural gas. Unexpected shut downs or curtailment of capacity of pipelines for maintenance
or integrity work because of actions taken by regulators could also affect the Corporation’s production, operations and
financial results. Furthermore, producers are increasingly turning to rail as an alternative means of transportation. In
recent years, the volume of crude oil shipped by rail in North America has increased dramatically. Any significant
change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays
in constructing new infrastructure systems and facilities could harm the Corporation’s business and, in turn, the
Corporation’s financial condition, results of operations and cash flows. In June 2021, TC Energy confirmed the
termination of the Keystone XL Pipeline. It is unclear what the direct impact of the loss of permit will be on the
Corporation. See “Industry Conditions – Pipelines”.
A portion of the Corporation’s production may be processed through facilities owned by third parties and over which
the Corporation does not have control. These facilities may discontinue or decrease operations either as a result of
normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could
materially adversely affect the Corporation’s ability to process its production and to deliver the same for sale.
Alternatives to and Changing Demand for Petroleum Products
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and
natural gas, and technological advances in fuel economy and energy generation devices could reduce the demand for
crude oil and other liquid hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to
decrease the use of fossil fuels and encourage the use of renewable fuel alternatives, which may lessen the demand
for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy
efficient products have a similar effect on the demand for oil and gas products. Kelt cannot predict the impact of
changing demand for oil and natural gas products, and any major changes may have a material adverse effect on Kelt’s
business, financial condition, results of operations and cash flows.
Possible Failure to Realize Anticipated Benefits of Acquisitions and Dispositions
As part of its ongoing strategy, the Corporation may complete acquisitions of assets or other entities in the future.
Achieving the benefits of completed and future acquisitions depends in part on successfully consolidating functions
and integrating operations, procedures and personnel in a timely and efficient manner, as well as the Corporation’s
ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and
operations with those of the Corporation. The integration of acquired businesses and entities requires the dedication
of substantial management effort, time and resources which may divert management’s focus and resources from other
strategic opportunities and from operational matters during this process. The integration process may result in the loss
of key employees and the disruption of ongoing business, customer and employee relationships that may adversely
affect the Corporation’s ability to achieve the anticipated benefits of any acquisitions. In addition, non-core assets may
be periodically disposed of so the Corporation can focus its efforts and resources more efficiently. Depending on the
state of the market for such non-core assets, certain non-core assets of the Corporation, if disposed of, may realize less
than their carrying value on the financial statements of the Corporation.
Capital Markets
Kelt, along with all other oil and gas entities, may have restricted access to capital, bank debt and equity. As future
capital expenditures will be financed out of funds generated from operations, non-core property dispositions,
borrowings and possible future equity sales, Kelt’s ability to do so is dependent on, among other factors, the overall
state of capital markets and investor appetite for investments in the energy industry and Kelt’s securities in particular.
To the extent that external sources of capital become limited or unavailable or available on onerous terms, Kelt’s
ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business,
financial condition and results of operations may be materially and adversely affected as a result.
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Based on current funds available and expected funds generated from operations, Kelt believes it has sufficient funds
available to fund its projected capital expenditures. However, if funds generated from operations are lower than
expected or capital costs for these projects exceed current estimates, or if Kelt incurs major unanticipated expense
related to development or maintenance of its existing properties, it may be required to seek additional capital to
maintain its capital expenditures at planned levels. Failure to obtain any financing necessary for Kelt’s capital
expenditure plans may result in a delay in development or production on Kelt’s properties.
Impact of Future Financings on Market Price
In order to finance future operations or acquisitions opportunities, the Corporation may raise funds through the
issuance of Common Shares or the issuance of debt instruments or securities convertible into Common Shares. The
Corporation cannot predict the size of future issuances of Common Shares or the issuance of debt instruments or other
securities convertible into Common Shares or the effect, if any, that future issuances and sales of the Corporation’s
securities will have on the market price of the Common Shares.
Regulatory
Various levels of governments impose extensive controls and regulations on oil and natural gas operations
(exploration, production, pricing, marketing and transportation). Governments may regulate or intervene with respect
to exploration and production activities, prices, taxes, royalties and the exportation of oil and natural gas. Amendments
to these controls and regulations may occur in response to economic or political conditions. See “Industry Conditions”
in this Annual Information Form. The implementation of new regulations or the modification of existing regulations
affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase the
Corporation’s costs, either of which may have a material adverse effect on the Corporation’s business, financial
condition, results of operations and prospects. Recent regulations include the temporary oil production curtailment
plan which began on January 1, 2019 announced by the Government of Alberta, see “Industry Conditions – Production
and Operation Regulations” in this Annual Information Form.
In addition to regulatory requirements pertaining to the production, marketing and sale of oil and natural gas mentioned
above, the Corporation’s business and financial condition could be influenced by federal legislation affecting, in
particular, foreign investment, through legislation such as the Competition Act (Canada) and the Investment Canada
Act (Canada).
Royalty Regimes
There can be no assurance that the federal government and the provincial governments of the western provinces will
not adopt a new or modify the royalty regime which may have an impact on the economics of the Corporation’s
projects. An increase in royalties would reduce the Corporation’s earnings and could make future capital investments,
or the Corporation’s operations, less economic. See “Industry Conditions - Provincial Royalties and Incentives” in
this Annual Information Form.
Insurance
Kelt’s involvement in the exploration for and development of oil and gas properties may result in Kelt becoming
subject to liability for pollution, blow-outs, property damage, personal injury and other hazards. Although Kelt has
obtained insurance in accordance with industry standards to address such risks, such insurance has limitations on
liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all
circumstances be insurable or, in certain circumstances, Kelt may elect not to obtain insurance to deal with specific
risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured
liabilities would reduce the funds available to Kelt. The occurrence of a significant event that Kelt is not fully insured
against, or the insolvency of the insurer of such event, could have a material adverse effect on Kelt’s financial position,
results of operations or prospects.
Operational Dependence
Other companies operate some of the assets in which Kelt has an interest. As a result, Kelt will have limited ability
to exercise influence over the operation of those assets or their associated costs, which could adversely affect Kelt’s
financial performance. Kelt’s return on assets operated by others will therefore depend upon a number of factors that
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may be outside of Kelt’s control, including the timing and amount of capital expenditures, the operator’s expertise
and financial resources, the approval of other participants, the selection of technology and risk management practices.
In addition, due to the current low and volatile commodity prices, many companies, including companies that may
operate some of the assets in which Kelt has an interest, may be in financial difficulty, which could impact their ability
to fund and pursue capital expenditures, carry out their operations in a safe and effective manner and satisfy regulatory
requirements with respect to abandonment and reclamation obligations. If companies that operate some of the assets
in which Kelt has an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation
obligations, Kelt may be required to satisfy such obligations and to seek recourse from such companies. To the extent
that any of such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to
bankruptcy or insolvency, it could result in such assets being shut-in, Kelt potentially becoming subject to additional
liabilities relating to such assets and Kelt having difficulty collecting revenue due from such operators. Any of these
factors could materially adversely affect Kelt’s financial and operational results.
Project Risks
Kelt manages a variety of small and large projects in the conduct of its business. Project delays may delay expected
revenues from operations. Significant project cost over-runs could make a project uneconomic. Kelt’s ability to
execute projects and market oil and natural gas will depend upon numerous factors beyond Kelt’s control, including:
the availability of processing capacity;
the availability and proximity of pipeline capacity;
the availability of storage capacity;
the supply of and demand for oil and natural gas;
the availability of alternative fuel sources;
the effects of inclement weather;
the availability of drilling and related equipment;
unexpected cost increases;
accidental events;
currency fluctuations;
changes in regulations;
the availability and productivity of skilled labour; and
the regulation of the oil and natural gas industry by various levels of government and governmental
agencies.
Because of these factors, Kelt could be unable to execute projects on time, on budget or at all, and may not be able to
effectively market the oil and natural gas that it produces.
Variations in Foreign Exchange Rates and Insurance Rates
World oil and gas prices are quoted in United States dollars and the price received by Canadian producers is therefore
affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time. In recent years, the Canadian
dollar has seen a material decrease in value against the United States dollar. Any material increases in the value of
the Canadian dollar may negatively impacted Kelt’s operating entities production revenues. Any increase in the future
Canadian/United States exchange rates could accordingly impact the future value of Kelt’s reserves as determined by
independent evaluators.
To the extent that Kelt engages in risk management activities related to foreign exchange rates, there is a credit risk
associated with counterparties with which Kelt may contract. An increase in interest rates could result in a significant
increase in the amount Kelt pays to service debt, which could negatively impact the market price of the Common
Shares.
Substantial Capital Requirements; Liquidity
Kelt anticipates that it will make substantial capital expenditures for the acquisition, exploration development and
production of oil and natural gas reserves in the future. If Kelt’s future revenues or reserves decline, Kelt may have
limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no
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assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these
requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms
acceptable to Kelt. Moreover, future activities may require Kelt to alter its capitalization significantly. The inability
of Kelt to access sufficient capital for its operations could have a material adverse effect on Kelt’s financial condition,
results of operations or prospects.
Issuance of Debt
Kelt may finance its capital program or acquisitions partially or wholly with debt, which may increase Kelt’s debt
levels above industry standards. Neither Kelt’s articles nor its bylaws limit the amount of indebtedness that Kelt may
incur. The level of Kelt’s indebtedness could impair Kelt’s ability to obtain additional financing in the future on a
timely basis to take advantage of business opportunities that may arise. Kelt’s ability to meet its debt service
obligations will depend on Kelt’s future operations which are subject to prevailing industry conditions and other
factors, many of which are beyond the control of Kelt. As certain of the indebtedness of Kelt bears interest at rates
which fluctuate with prevailing interest rates, increases in such rates would increase Kelt’s interest payment
obligations and could have a material adverse effect on Kelt’s financial condition and results of operations. Further,
Kelt’s indebtedness is secured by substantially all of Kelt’s assets. In the event of a violation by Kelt of any of its
loan covenants or any other default by Kelt on its obligations relating to its indebtedness, the lender could declare
such indebtedness to be immediately due and payable and, in certain cases, foreclose on Kelt’s assets.
Hedging
Kelt may enter into agreements to receive fixed prices on its oil and natural gas production to offset risk of revenue
losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements,
Kelt will not benefit from such increases. Similarly, Kelt may enter into agreements to fix the exchange rate of
Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value
compared to the United States dollar, however, if the Canadian dollar declines in value compared to the United States
dollar, Kelt will not benefit from its fluctuating exchange rate. In addition, Kelt may enter into agreements to fix the
interest rate on its debt to offset the risk of higher interest expenses during a period of rising borrowing costs, however,
if borrowing costs decline, Kelt will not be able to benefit from such declines.
Competition
The oil and gas industry is highly competitive. Kelt actively competes for reserve acquisitions, exploration leases,
licences and concessions and skilled industry personnel with a substantial number of other oil and gas entities, many
of which have significantly greater financial resources, staff and facilities than Kelt. Kelt’s competitors include
integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual
producers and operators. Certain of Kelt’s customers and potential customers may themselves explore for oil and
natural gas and the results of such exploration efforts could affect Kelt’s ability to sell or supply oil or gas to these
customers in the future. Kelt’s ability to successfully bid on and acquire additional property rights, to discover reserves
to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be
dependent upon developing and maintaining close working relationships with its future industry partners and joint
operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly
competitive environment. Competitive factors in the distribution and marketing of oil and natural gas include price
and methods and reliability of delivery and storage. Competition may also be presented by alternate fuel sources.
Cost of New Technologies
The oil industry is characterized by rapid and significant technological advancements and introductions of new
products and services utilizing new technologies. Other oil and gas companies may have greater financial, technical
and personnel resources that allow them to enjoy technological advantages and may in the future allow them to
implement new technologies before the Corporation. There can be no assurance that the Corporation will be able to
respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost.
One or more of the technologies currently utilized by the Corporation or implemented in the future may become
obsolete. In such case, the Corporation’s business, financial condition and results of operations could be materially
adversely affected. If the Corporation is unable to utilize the most advanced commercially available technology, its
business, financial condition and results of operations could be materially adversely affected.
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Title
Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial
expense. In accordance with industry practice, Kelt will conduct such title reviews in connection with its principal
properties as it believes are commensurate with the value of such properties. However, no absolute assurances can be
given that title defects do not exist. If title defects do exist, it is possible that Kelt may lose all or a portion of its right
title and interest in and to the properties to which the title defects relate.
Reserve Estimates
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and cash flows
to be derived therefrom, including many factors beyond Kelt’s control. The information concerning reserves and
associated cash flow set forth in this Annual Information Form represents estimates only. In general, estimates of
economically recoverable oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a
number of variable factors and assumptions, such as historical production from the properties, production rates,
ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil, natural gas and NGL,
royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may
vary from actual results. For those reasons, estimates of the economically recoverable oil, natural gas and NGL
reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and
estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at
different times, may vary. Kelt’s actual production, revenues, taxes and development and operating expenditures with
respect to its reserves will vary from estimates thereof and such variations could be material. Further, the evaluations
are based, in part, on the assumed success of the exploitation activities intended to be undertaken in future years. The
reserves and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent
that such exploitation activities do not achieve the level of success assumed in the evaluation.
In accordance with applicable securities laws, Sproule has used forecast price and cost estimates in calculating
reserve quantities. Actual future net cash flows will be affected by other factors such as actual production
levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural
gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual
production and cash flows derived therefrom will vary from the estimates contained in the Sproule Report, and
such variations could be material. The Sproule Report is based in part on the assumed success of activities Kelt
intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained
in the Sproule Report will be reduced to the extent that such activities do not achieve the level of success
assumed in the Sproule Report.
The Sproule Report is effective as of a specific effective date and has not been updated and thus does not reflect
changes in Kelt’s reserves since that date.
Reserve Replacement
Kelt’s future oil and natural gas reserves, production, and cash flows to be derived therefrom are highly dependent on
Kelt successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing
reserves Kelt may have at any particular time and the production therefrom will decline over time as such existing
reserves are exploited. A future increase in Kelt’s reserves will depend not only on Kelt’s ability to develop any
properties it may have, but also on its ability to select and acquire suitable producing properties or prospects. There
can be no assurance that Kelt’s future exploration and development efforts will result in the discovery and development
of additional commercial accumulations of oil and natural gas.
Reliance on Key Personnel
Kelt’s future success depends in large measure on certain key personnel. The exploration for, and the development
and production of, oil and natural gas with respect to its assets requires experienced executive and management
personnel and operational employees and contractors with expertise in a wide range of areas. There can be no
assurance that all of the required employees and contractors with the necessary expertise will be available. Further,
the loss of any key personnel may have a material adverse effect on Kelt’s business, financial condition, results of
operations and prospects. Kelt currently does not have any “key man” insurance in place.
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Any inability on the part of Kelt to attract and retain qualified personnel may delay or interrupt the exploration for,
and development and production of, oil and natural gas with respect to Kelt’s assets. Sustained delays or interruptions
could have a material adverse effect on the financial condition and performance of Kelt. In addition, rising personnel
costs would adversely impact the costs associated with the exploration for, and development and production of, oil
and natural gas in respect of Kelt’s assets, which could be significant and material.
Management of Growth
Kelt may be subject to growth-related risks including capacity constraints and pressure on its internal systems and
controls. The ability of Kelt to manage growth effectively will require it to continue to implement and improve its
operations and financial systems and to expand, train and manage its employee base. The inability of Kelt to deal
with this growth could have a material adverse impact on its business, operations and prospects.
Permits and Licenses
The operations of Kelt may require licenses and permits from various governmental authorities. There can be no
assurance that Kelt will be able to obtain all necessary licenses and permits that may be required to carry out
exploration and development at its projects. Further, if the Corporation or the holder of the licence or lease fails to
meet the specific requirement of a licence or lease, the licence or lease may terminate or expire. There can be no
assurance that any of the obligations required to maintain each licence or lease will be met. The termination or
expiration of the Corporation’s licenses or leases or the working interests relating to a licence or lease may have a
material adverse effect on the Corporation’s business, financial condition, results of operations and prospects.
Liability Management
Alberta and British Columbia have developed liability management programs designed to prevent taxpayers from
incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and
pipelines in the event that a licensee or permit holder becomes defunct. These programs generally involve an
assessment of the ratio of a licensee’s deemed assets to deemed liabilities. If a licensee’s deemed liabilities exceed its
deemed assets, a security deposit is required. Changes of the ratio of Kelt’s deemed assets to deemed liabilities or
changes to the requirements of liability management programs may result in significant increases to the security that
must be posted. In addition, the liability management system may prevent or interfere with Kelt’s ability to acquire or
dispose of assets as both the vendor and the purchaser of oil and gas assets must be in compliance with the liability
management programs (both before and after the transfer of the assets) for the applicable regulatory agency to allow
for the transfer of such assets. See “Industry Conditions - Liability Management Rating Programs” in the Annual
Information Form.
Access Restrictions
The Corporation’s business depends in part upon the ability to access its lands to operate, as well as the availability,
proximity, and capacity of oil and natural gas gathering systems, pipelines and/or rail transportation systems and
processing facilities to provide access to markets for its production. Federal and provincial, regulation of oil and
natural gas production and processing and transportation could adversely affect the Corporation’s ability to produce
and market oil, natural gas and NGLs. Special interest groups could prevent access to leased land or oppose
infrastructure development, resulting in operational delays, or even cancellation of construction of the required
infrastructure, both of which frustrate the Corporation’s ability to operate, produce and market its products or restrict
shipping of commodities by truck, pipeline or rail.
Availability of Drilling Equipment
Oil and natural gas exploration and development activities are dependent on the availability of drilling and related
equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or
access restrictions may affect the availability of such equipment to Kelt and may delay exploration and development
activities.
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Global Financial Markets
Market events and conditions, including disruptions in the international credit markets and other financial systems,
and the deterioration of global economic conditions caused significant volatility to commodity prices over the last few
years. These conditions have resulted in a loss of confidence in the broader U.S. and global credit and financial markets
and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and
creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased
credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the
general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial
institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. These
factors have negatively impacted company valuations and may continue to impact the performance of the global
economy going forward.
If the economic climate in the U.S. or the world generally deteriorates further, demand for petroleum products could
diminish further and prices for oil and natural gas could decrease further, which could adversely impact Kelt’s results
of operations, liquidity and financial condition.
Seasonality
The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and
spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments
enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also,
certain oil and gas producing areas are located in areas that are inaccessible other than during the winter months
because the ground surrounding the sites in these areas consists of swampy terrain. There can be no assurance that
these seasonal factors will not adversely affect the timing and scope of Kelt’s exploration and development activities,
which could in turn have a material adverse impact on Kelt’s business, operations and prospects.
Third Party Credit Risk
Kelt is, or may be exposed to, third party credit risk through its contractual arrangements with its current or future
joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such
entities fail to meet their contractual obligations to Kelt, such failures could have a material adverse effect on Kelt and
its cash flow from operations. In addition, poor credit conditions in the industry and of joint venture partners may
impact a joint venture partner’s willingness to participate in Kelt’s ongoing capital program, potentially delaying the
program and the results of such program until Kelt finds a suitable alternative partner.
Hydraulic Fracturing
Concern has been expressed over the potential environmental impact of hydraulic fracturing operations, including
water aquifer contamination and other qualitative and quantitative effects on water resources as large quantities of
water are used and injected fluids either remain underground or flow back to the surface to be collected, treated and
disposed of. Regulatory authorities in certain jurisdictions have announced initiatives in response to such concerns.
Federal, provincial and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as
governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, and
adversely affect Kelt’s production. Public perception of environmental risks associated with hydraulic fracturing can
further increase pressure to adopt new laws, regulation or permitting requirements or lead to regulatory delays, legal
proceedings and/or reputational impacts. Any new laws, regulations or permitting requirements regarding hydraulic
fracturing could lead to operational delay, increased operating costs, and third-party or governmental claims. They
could also increase Kelt’s costs of compliance and doing business as well as delay the development of hydrocarbon
(natural gas and oil) resources from shale formations, which may not be commercial without the use of hydraulic
fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that Kelt is
ultimately able to produce from its reserves.
In the event federal, provincial, local, or municipal legal restrictions are adopted in areas where Kelt is currently
conducting, or in the future plan to conduct operations, Kelt may incur additional costs to comply with such
requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration,
development, or production activities, and perhaps even be precluded from the drilling of wells. In addition, if
hydraulic fracturing becomes more regulated, Kelt’s fracturing activities could become subject to additional permitting
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requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing
could also reduce the amount of oil and natural gas that Kelt is ultimately able to produce from its reserves.
Political Risks
The marketability and price of oil and natural gas that may be acquired or discovered by Kelt is and will continue to
be affected by political events throughout the world that cause disruptions in the supply of oil. Conflicts, or conversely
peaceful developments, arising in the Middle East, and other areas of the world, have a significant impact on the price
of oil and natural gas. Any particular event could result in a material decline in prices and therefore result in a
reduction of Kelt’s net production revenue.
In addition, Kelt’s expected oil and natural gas properties, wells and facilities could be subject to a terrorist attack. As
the oil and gas industry in Canada is a key supplier of energy to the United States, certain terrorist groups may target
Canadian oil and gas properties, wells and facilities in an effort to choke the United States economy. If any of Kelt’s
properties, wells or facilities are the subject of terrorist attack it could have a material adverse effect on Kelt. Kelt
does not have insurance to protect against the risk from terrorism.
Tax Horizon
It is expected, based upon current legislation, the projections contained in the Sproule Report and various other
assumptions that no cash income taxes are to be paid by Kelt in the near future. If a lower level of capital expenditures
than those contained in the Sproule Report is incurred or, should the assumptions used by Kelt prove to be inaccurate,
Kelt may be required to pay cash income taxes sooner than anticipated, which will reduce cash flow available to Kelt.
Potential Conflicts of Interest
There may be circumstances in which the interests of Kelt and its affiliates will conflict with those of shareholders.
Kelt and its affiliates may acquire oil and natural gas properties on their own behalf or on behalf of persons other than
the shareholders. Neither Kelt, nor its management, will carry on their full-time activity on behalf of shareholders and,
when acting on their own behalf or on behalf of others, may at times act in competition with the interests of
shareholders.
In the event of such conflicts, decisions will be made on a basis consistent with the provisions of any relevant
contractual arrangements and objectives and financial resources of each group of interested parties. Kelt will use all
reasonable efforts to resolve such conflicts of interest in a manner which will treat Kelt, and the other interested party,
fairly taking into account all of the circumstances of Kelt and such interested party and to act honestly and in good
faith in resolving such matters.
Circumstances may arise where members of the Board of Directors are directors or officers of corporations which are
in competition to the interests of Kelt. No assurances can be given that opportunities identified by such board members
will be provided to Kelt.
Certain directors of Kelt are also directors of other oil and gas companies and as such may, in certain circumstances,
have a conflict of interest requiring them to abstain from certain decisions. Conflicts, if any, will be subject to the
procedures and remedies of the ABCA. See “Directors and Officers – Conflicts of Interest” in this Annual Information
Form.
Internal Controls
Effective internal controls are necessary for Kelt to provide reliable financial reports and to help prevent fraud.
Although Kelt will undertake a number of procedures in order to help ensure the reliability of its financial reports,
including those imposed on it under Canadian securities laws, Kelt cannot be certain that such measures will ensure
that Kelt will maintain adequate control over financial processes and reporting.
Failure to implement required new or improved controls, or difficulties encountered in their implementation, could
harm Kelt’s results of operations or cause it to fail to meet its reporting obligations. If Kelt or its independent auditors
discover a material weakness, the disclosure of that fact, even if quickly remedied, could reduce the market’s
confidence in Kelt financial statements and harm the trading price of the Common Shares.
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Dividends
To date, Kelt has not paid any dividends on its Common Shares and does not anticipate the payment of any dividends
on its Common Shares for the foreseeable future, though it is a possibility that the Corporation may pay dividends in
the future if it has started generating sufficient positive cash flow, or a dividend as a result of an asset sale. Any future
determination to pay dividends will be at the discretion of the Board and will depend on the financial condition,
business environment, operating results, capital requirements, any contractual restrictions on the payment of dividends
and any other factors that the Board deems relevant.
Dilution
Kelt may make future acquisitions or enter into financings or other transactions involving the issuance of securities of
Kelt which may be dilutive. Common Shares, including rights, warrants, special warrants, subscription receipts and
other securities to purchase, to convert into or to exchange into Common Shares, may be created, issued, sold and
delivered on such terms and conditions and at such times as the Board of Directors may determine. In addition, the
Corporation may issue additional Common Shares pursuant to the Corporation’s stock option plan or restricted share
unit plan. The issuance of these Common Shares would result in dilution to holders of Common Shares.
Litigation
In the normal course of the Corporation’s operations, it may become involved in, named as a party to, or be the subject
of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, related to personal
injuries, property damage, property tax, land rights, the environment and contract disputes. The outcome of
outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to the
Corporation and as a result, could have a material adverse effect on the Corporation’s assets, liabilities, business,
financial condition and results of operations.
Breach of Confidentiality
While discussing potential business relationships or other transactions with third parties, the Corporation may disclose
confidential information relating to the business, operations or affairs of the Corporation. Although confidentiality
agreements are signed by third parties prior to the disclosure of any confidential information, a breach could put the
Corporation at competitive risk and may cause significant damage to its business. The harm to the Corporation’s
business from a breach of confidentiality cannot presently be quantified, but may be material and may not be
compensable in damages. There is no assurance that, in the event of a breach of confidentiality, the Corporation will
be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely
manner, if at all, in order to prevent or mitigate any damage to its business that such a breach of confidentiality may
cause.
Volatility of Market Price of Common Shares
The market price of the Common Shares may be volatile. The volatility may affect the ability of holders to sell the
Common Shares at an advantageous price. Market price fluctuations in the Common Shares may be due to the
Corporation’s operating results failing to meet the expectations of securities analysts or investors in any quarter,
downward revision in securities analysts’ estimates, governmental regulatory action, adverse change in general market
conditions or economic trends, acquisitions, dispositions or other material public announcements by the Corporation
or its competitors, along with a variety of additional factors, including, without limitation, those set forth under
“Forward-Looking Statements and Information” in this Annual Information Form. In addition, the market price for
securities in the stock markets, including the TSX, has recently experienced significant price and trading fluctuations.
These fluctuations have resulted in volatility in the market prices of securities that are often unrelated or
disproportionate to changes in operating performance. These broad market fluctuations may adversely affect the
market prices of the Common Shares.
Information Technology Systems and Cyber-Security
The Corporation relies heavily on information technology, such as computer hardware and software systems, in order
to properly operate its business. In the event the Corporation is unable to regularly deploy software and hardware,
effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and
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efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of
data, compromise confidential customer or employee information, result in the disruption of business, theft or
extortion of funds, regulatory infractions, loss of competitive advantage and reputational damage. In addition,
information systems could be damaged or interrupted by natural disasters, force majeure events, telecommunications
failures, power loss, acts of war or terrorism, computer viruses, malicious code, physical or electronic security
breaches, intentional or inadvertent user misuse or error, or similar events or disruptions. Any of these or other events
could cause interruptions, delays, loss of critical and/or sensitive data or similar effects, which could have a material
adverse impact on the protection of intellectual property, and confidential and proprietary information, and on the
Corporation’s business, financial condition, results of operations and cash flows.
In the ordinary course of business, the Corporation collects, uses and stores sensitive data, including intellectual
property, proprietary business information and personal information of the Corporation’s employees and third parties.
Despite the Corporation’s security measures, its information systems, technology and infrastructure may be vulnerable
to attacks by hackers and/or cyberterrorists or breaches due to employee error, malfeasance or other disruptions. Any
such breach could compromise information used or stored on the Corporation’s systems and/or networks and, as a
result, the information could be accessed, publicly disclosed, lost or stolen.
To date the Corporation has not experienced any material losses relating to cyber-attacks or other information security
breaches. However, there can be no assurance that the Corporation will not incur such losses in the future. Any such
access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that
protect the privacy of personal information, regulatory penalties or other negative consequences, including disruption
to the Corporation’s operations and damage to its reputation, which could have a material adverse effect on the
Corporation’s business, financial condition, results of operations and cash flows. Although the Corporation maintains
a risk management program, which includes an insurance component that may provide coverage for the operational
impacts from an attack to, or breach of, Kelt’s information technology and infrastructure, including process control
systems, the Corporation does not maintain stand-alone cyber insurance. Furthermore, not all cyber risks are insurable.
As a result, Kelt’s existing insurance may not provide adequate coverage for losses stemming from a cyber-attack to,
or breach of, its information technology and infrastructure.
Reputation Risk
The Corporation relies on its reputation to build and maintain positive relationships with stakeholders, to recruit and
retain staff, and to be a credible trusted company. Any actions that Kelt takes that causes a negative public opinion
has the potential to negatively impact the Corporation’s reputation which may adversely impact its share price,
development plans or its ability to continue operations.
Forward-Looking Statements and Information May Prove Inaccurate
Shareholders and prospective investors are cautioned not to place undue reliance on the Corporation’s forward-looking
statements and information. By its nature, forward-looking statements and information involve numerous
assumptions, known and unknown risk and uncertainties, of both a general and specific nature, that could cause actual
results to differ materially from those suggested by the forward-looking information or contribute to the possibility
that predictions, forecasts or projections will prove to be materially inaccurate. Additional information on the risks,
assumptions and uncertainties related to forward-looking statements and information are found under the heading
“Forward-Looking Statements and Information” in this Annual Information Form.
Canadian Government Regulation
INDUSTRY CONDITIONS
The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including
land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation
enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements
among the governments of Canada, Alberta and British Columbia, all of which should be carefully considered by
investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect the operations
of Kelt in a manner materially different than they would affect other oil and gas companies of similar size. All current
legislation is a matter of public record and Kelt is unable to predict what additional legislation or amendments may be
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enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the
oil and gas industry in the provinces of Alberta and British Columbia.
Pricing and Marketing – Oil
The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market
determines the price of oil. Worldwide supply and demand factors primarily determine oil prices; however prices are
also influenced by regional market and transportation issues. The specific price depends in part on oil quality, prices
of competing fuels, distance to market, the availability and cost of transportation capacity to various markets, value
of refined products, the supply/demand balance and contractual terms of sale.
Pricing and Marketing – Natural Gas
Alberta’s natural gas market has been deregulated since 1985. Supply and demand determine the price of natural gas
and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission
system such as the Alberta “NIT” (Nova Inventory Transfer), at a storage facility, at the inlet to a utility system or at
the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer’s own
arrangements (whether long or short-term contracts and the specific point of sale). As natural gas is also traded on
trading platforms such as the Natural Gas Exchange (NGX), Intercontinental Exchange or the New York Mercantile
Exchange (NYMEX) in the United States, spot and future prices can also be influenced by supply and demand
fundamentals on these platforms.
Pricing and Marketing – Natural Gas Liquids
In Canada, the price of NGL sold in intra-provincial, interprovincial and international trade is determined by
negotiation between buyers and sellers. Such price depends, in part, on the quality of the NGL, prices of competing
chemical feedstock, distance to market, access to downstream transportation, length of contract term, the
supply/demand balance and other contractual terms.
Exports from Canada
On August 28, 2019, Bill C-69 came into force, replacing, among other things, the National Energy Board Act (the
“NEB Act”) with the Canadian Energy Regulator Act (Canada) (the “CERA”), and replacing the NEB with the CER.
The CER has assumed the National Energy Board’s (the “NEB”) responsibilities broadly, including with respect to
the export of crude oil, natural gas and NGL from Canada. The legislative regime relating to exports of crude oil,
natural gas and NGL from Canada has not changed substantively under the new regime. See “Industry Conditions -
Environmental Regulation – Federal” in this Annual Information Form. Exports of crude oil, natural gas and NGL
from Canada are subject to the CERA.
As to price, exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts
continue to meet certain criteria prescribed by the CER and the federal government. The Corporation does not directly
enter into contracts to export the Corporation’s production outside of Canada.
As discussed in more detail below, one major constraint to the export of crude oil, natural gas and NGLs outside of
Canada is the deficit of overall pipeline and other transportation capacity to transport production from Western Canada
to the United States and other international markets. Although certain pipeline and other transportation projects are
underway, many contemplated projects have been cancelled or delayed due to regulatory hurdles, court challenges
and economic and other socio-political factors. Major pipeline and other transportation infrastructure projects typically
require a significant length of time to complete once all regulatory and other hurdles have been cleared. In addition,
production of crude oil, natural gas and NGLs in Canada is expected to continue to increase, which may further
exacerbate the transportation capacity deficit.
Pipelines
Producers negotiate with pipeline operators (or other transport providers) to transport their products to market on a
firm or interruptible basis. Transportation availability is highly variable across different jurisdictions and regions. This
variability can determine the nature of transportation commitments available, the number of potential customers that
can be reached in a cost-effective manner and the price received. Due to growing production and a lack of new and
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expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low commodity
pricing relative to other markets in the last several years.
Under the Canadian constitution, interprovincial and international pipelines fall within the federal government’s
jurisdiction and require a regulatory review and approval by Cabinet. However, recent years have seen a perceived
lack of policy and regulatory certainty at a federal level. The federal government amended the federal approval process
with the CER, which aims to create efficiencies in the project approval process while upholding stringent
environmental and regulatory standards. However, as the CER has not yet undertaken a major project approval, it is
unclear how the new regulator operates compared to the NEB and whether it will result in a more efficient approval
process. Lack of regulatory certainty is likely to influence investment decisions for major projects. Even when projects
are approved at a federal level, such projects often face further delays due to interference by provincial and municipal
governments. Additional delays causing further uncertainty may result from legal opposition related to issues such as
Indigenous rights and title, the government’s duty to consult and accommodate indigenous peoples, and the sufficiency
of all relevant environmental review processes. Export pipelines from Canada to the United States face additional
unpredictability as such pipelines require approvals from several levels of government in the United States.
In the face of such regulatory uncertainty, the Canadian crude oil and natural gas industry has experienced significant
difficulty expanding the existing network of transportation infrastructure for crude oil, natural gas and NGLs,
including pipelines, rail, trucks and marine transport. Improved access to global markets through the Midwest United
States and export shipping terminals on the west coast of Canada could help to alleviate downward pressure on
commodity prices. Several proposals have been announced to increase pipeline capacity from Western Canada to
Eastern Canada, the United States, and other international markets via export terminals. While certain projects are
proceeding, the regulatory approval process and other factors related to transportation and export infrastructure have
led to the delay, suspension or cancellation of a number of pipeline projects.
With respect to the current state of the transportation and exportation of crude oil from Western Canada to domestic
and international markets, the Enbridge Line 3 Replacement from Hardisty, Alberta, to Superior, Wisconsin came into
service in October 2021. The Line 3 Replacement, originally expected to be in-service in late 2019, faced significant
permitting difficulties in the United States, resulting in the two-year delay. The pipeline provides and incremental
370,000 bbls/d of export capacity from Western Canada into the United States.
The Trans Mountain Pipeline expansion received Cabinet approval in November 2016. Following a period of political
opposition in British Columbia, the federal government acquired the Trans Mountain Pipeline in August 2018.
Following the resolution of a number of legal challenges and a second regulatory hearing, construction on the Trans
Mountain Pipeline expansion commenced in late 2019. Originally estimated at $12.6 billion, the Trans Mountain
Pipeline budget has risen to $21.4 billion as of February 2022. The pipeline is expected to be in service in the third
quarter of 2023, an extension from Trans Mountain’s December 2022 estimate. The budget increase and in-service
date delay have been attributed to, among other things, the ongoing effects of the COVID-19 pandemic and the
widespread flooding in British Columbia in late 2021.
In 2021, the Biden administration in the U.S. revoked certain permits required for the construction of the Keystone
X.L. pipeline, resulting in the projects cancellation by TC Energy.
In November 2020, the Attorney General of Michigan filed a lawsuit to terminate an easement that allows the Enbridge
Line 5 pipeline system to operate below the Straits of Mackinac, potentially forcing the lines comprising this segment
of the pipeline system to be shut down by May 2021. Enbridge filed a federal complaint in late November 2020 in the
United States District Court for the Western District of Michigan and is seeking an injunction to prevent the
termination of the easement. Enbridge stated in January 2021 that it intends to defy the shut down order, as the dual
pipelines are in full compliance with U.S. federal safety standards. The Government of Canada invoked a 1977 treaty
with the United States on October 4, 2021, triggering bilateral negotiations over the pipeline. On December 15, 2021,
Enbridge moved to transfer the Attorney General’s lawsuit from Michigan State Court to United States Federal Court.
In August 2019, Enbridge initiated an open season for the Enbridge mainline system, which has historically operated
as a common carrier pipeline system transporting crude oil. The changes that Enbridge intends to implement include
the transition of the mainline system from a common carrier to a primarily contract carrier pipeline, wherein shippers
will have to commit to reserved space in the pipeline for a fixed term, with only 10% of available capacity reserved
for nominations. If the service change is approved, shippers seeking firm capacity on the Enbridge system would no
longer be able to rely on the nomination process and would have to enter long-term contracts for service.
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Several shippers challenged Enbridge’s open season and, in particular, Enbridge’s ability to engage in an open season
without first obtaining prior regulatory approval to implement a contract carriage model. Following an expedited
hearing process, the CER decided to shut down the open season, citing concerns about fairness and uncertainty
regarding the ultimate terms and conditions of service. On December 19, 2019, Enbridge applied to the CER for
approval of the proposed service and tolling framework. On November 26, 2021, the CER issued its Reasons for
Decision in Enbridge Pipelines Inc. RH-001-2020, denying the application to introduce firm service on the Canadian
Mainline. If approved, the application would have made 90% of the Canadian Mainline’s currently uncommitted
capacity subject to firm contracts for priority access, with contract terms ranging from eight to 20 years. Contracts for
firm service were to be awarded through an open season process put forward as part of the application.
Crude Oil and Bitumen by Rail
In February 2020, the federal government announced that trains hauling more than 20 cars carrying crude oil or diluted
bitumen, would be subject to reduced speed limits following two derailments that led to fires and oil spills in
Saskatchewan. The order was updated in early April and will remain in place until permanent rule changes are
approved. As a result, trains subject to the order will be required to adhere to the reduced speed limits announced in
February 2020 within metropolitan areas, with further mandatory speed reductions applying outside of metropolitan
areas during winter months (November 15 to March 15).
Curtailment
In December 2018, the Government of Alberta announced that, commencing January 1, 2019, it would mandate a
short-term reduction in provincial crude oil and crude bitumen production. Curtailment first took effect on January 1,
2019, limiting province-wide production of crude oil and crude bitumen to 3.56 million bbl/d. The curtailment rate
dropped gradually over the course of 2019 and was set at 3.81 million bbl/d through 2020. The Curtailment Rules,
which were set to be repealed on December 31, 2020, were extended to December 31, 2021. On December 9, 2021,
the Government of Alberta announced that the provincial policy on restraining oil production, a strategy to reduce
price-depressing gluts, would end December 31, 2021.
Trade Agreements
The United States-Mexico-Canada Agreement (“USMCA”) replaced the North American Free Trade Agreement
(“NAFTA”) on July 1, 2020. Under the USMCA, energy export restrictions are no longer subject to the requirement
that they do not reduce the proportion of energy resources exported relative to the total supply of goods of the party
maintaining the restriction as compared to the proportion prevailing in the most recent 36 month period. In addition,
the USMCA includes a change to the rules of origin for crude oil that should make it easier for exporters to qualify
for duty-free treatment on shipments to other USMCA parties. In particular, the origin of the diluent that is used to
facilitate the transportation of crude petroleum oils is disregarded, provided that the diluent constitutes no more than
40 per cent by volume of the goods. The United States remains Canada’s primary trading partner and the largest
international market for the export of oil, natural gas and NGLs from Canada, therefore the implementation of the
USMCA could impact Western Canada’s oil and gas industry at large, including Kelt’s business.
Canada has also pursued a number of other international free trade agreements with other countries around the world.
As a result, a number of free trade or similar agreements are in force between Canada and certain other countries while
in other circumstances Canada has been unsuccessful in its efforts. Canada and the European Union recently agreed
to the Comprehensive Economic and Trade Agreement (“CETA”), which provides for duty-free, quota-free market
access for Canadian oil and gas products to the European Union. Although CETA remains subject to ratification by
certain national legislatures in the European Union, provisional application of CETA commenced on September 21,
2017. In light of the United Kingdom’s departure from the European Union (“Brexit”) on January 31, 2020, the United
Kingdom and Canada have reached an interim post-Brexit trade agreement, the Canada-United Kingdom Trade
Continuity Agreement (“CUKTCA”). On December 9, 2020, the Government of Canada introduced Bill C-18, an
Act to Implement the Trade Continuity Agreement. CETA ceased to apply to Canada-United Kingdom trade on
January 1, 2021. The CUKTCA replicates CETA on a bilateral basis and is meant to maintain the status quo of the
Canada-United Kingdom trade relationship.
In addition, Canada and ten other countries signed the Comprehensive and Progressive Agreement for Trans-Pacific
Partnership (“CPTPP”) on March 8, 2018. The CPTPP has been ratified by seven countries, including Canada.
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While it is uncertain what effect CETA, CUKTCA, CPTPP or any other trade agreements will have on the oil and gas
industry in Canada, the lack of available infrastructure for the offshore export of oil and gas may limit the ability of
Canadian oil and gas producers to benefit from such trade agreements.
Extractive Sector Transparency Measures Act
The Extractive Sector Transparency Measures Act (Canada) (“ESTMA”), a federal regime for the mandatory
reporting of payments to government, came into force on June 1, 2015. ESTMA contains broad reporting obligations
with respect to payments to governments and state owned entities, including employees and public office holders,
made by Canadian businesses involved in resource extraction. Under ESTMA, all payments made to payees (broadly
defined to include any government or state owned enterprise) must be reported annually if the aggregate of all
payments in a particular category to a particular payee exceeds $100,000 per financial year. The categories of
payments include taxes, royalties, fees, bonuses, dividends and infrastructure improvement payments. Failure to
comply with the reporting obligations under ESTMA is punishable upon summary conviction with a fine of up to
$250,000. In addition, each day that passes prior to a non-compliant report being corrected forms a new offence, and
therefore, a payment that goes unreported for a year could result in over $9.0 million in total liability.
Provincial Royalties and Incentives
General
In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties,
production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of
crude oil, NGL, sulphur and natural gas production. Royalties payable on production from lands other than Crown
lands are determined by negotiation between the mineral freehold owner and the lessee, although production from
such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are
determined by governmental regulation and are generally calculated as a percentage of the value of gross production.
The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical
location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other
royalties and royalty-like interests are carved out of the working interest owner’s interest through non-public
transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net
carried interests.
Occasionally the governments of the western Canadian provinces create incentive programs for exploration and
development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are
generally introduced when commodity prices are low to encourage exploration and development activity by improving
earnings and cash flow within the industry.
The federal government also creates incentives and other financial aid programs intended to assist businesses operating
in the oil and gas industry. Recently, these programs, including, but not limited to, programs that provide direct
financial support to companies operating in the oil and gas industry and/or targeted funding for various initiatives
related to industry diversification and environmental matters, including those programs created in response to the
COVID-19 pandemic such as the various short-term loan programs and the Canada Emergency Wage Subsidy, for
example, have been administered through federal agencies such as the Business Development Bank of Canada, Natural
Resources Canada, Export Development Canada, Innovation, Science and Economic Development Canada and, in
some cases, the Canada Revenue Agency.
Alberta
In Alberta, oil and natural gas producers are responsible for calculating their royalty rate on an ongoing basis. The
Crown’s royalty share of production is payable monthly and producers must submit their records showing the royalty
calculation. The Mines and Minerals Act was amended in 2014 to shorten the window during which producers can
submit amendments to their royalty calculations before they become statute-barred, from four years to three.
In 2016, the Government of Alberta adopted a modernized Crown royalty framework (the “Modernized
Framework”) that applies to all conventional oil (i.e., not oil sands) and natural gas wells drilled after December 31,
2016 that produce Crown owned resources. The previous royalty framework (the “Old Framework”) will continue
to apply to wells producing Crown owned resources that were drilled prior to January 1, 2017 until December 31,
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2026, following which time they will become subject to the Modernized Framework. The Royalty Guarantee Act
(Alberta), came into effect on July 18, 2019, and provides that no major changes will be made to the current oil and
natural gas royalty structure for a period of at least 10 years.
Royalties on production from wells subject to the Modernized Framework are determined on a “revenue-minus-costs”
basis. The cost component is based on a Drilling and Completion Cost Allowance formula that relies, in part, on the
industry’s average drilling and completion costs, determined annually by the AER, and incorporates information
specific to each well such as vertical depth and lateral length.
Under the Modernized Framework, producers initially pay a flat royalty of 5% on production revenue from each
producing well until payout, which is the point at which cumulative gross revenues from the well equals the applicable
Drilling and Completion Cost Allowance. After payout, producers pay an increased royalty of up to 40% that will
vary depending on the nature of the resource and market prices. Once the rate of production from a well is too low to
sustain the full royalty burden, its royalty rate is gradually adjusted downward as production declines, eventually
reaching a floor of 5%.
Under the Old Framework, royalty rates for conventional oil production can be as high as 40% and royalty rates for
natural gas production can be as high as 36%. Similar to the Modernized Framework, these rates vary based on the
nature of the resource and market prices. The natural gas royalty formula also provides for a reduction based on the
measured depth of the well, as well as the acid gas content of the produced gas.
In addition to royalties, producers of oil and natural gas from Crown lands in Alberta are also required to pay annual
rentals to the Government of Alberta.
British Columbia
On October 7, 2021, the Government of British Columbia launched a comprehensive review of its oil and gas royalty
system. Based on the outcomes of this review and input received from the public, changes to the royalty regime are
expected to be made in the spring 2022. Results of the public engagement portion of the review released in February
2022 indicated that the majority of British Columbians are in favour of a “revamped royalty system that puts the
interest of British Columbians first and eliminates outdated, inefficient fossil fuel subsidies”. Until the changes to the
regime are implemented, the current system, established under the 1992 Petroleum and Natural Gas Royalty and
Freehold Production Tax Regulation, will continue to apply.
Under the current system, Crown royalties payable on the production of oil and natural gas in British Columbia vary
by market price, well type and the characteristics of the substances being produced. Producers of oil and natural gas
receive royalty invoices each month for every well or unitized tract that is producing and/or reporting sales.
Crown royalties payable on the production of oil and natural gas in British Columbia vary by market price, well type
and the characteristics of the substances being produced. Producers of oil and natural gas receive royalty invoices each
month for every well or unitized tract that is producing and/or reporting sales. The Crown royalty rate for oil can be
as high 40% and depends on factors such as the volume of oil produced from a particular well or unitized tract and its
vintage. Royalty rates are reduced on certain wells, including low-productivity wells, to reflect higher per-unit costs
of exploration and extraction. The Crown royalty rate for natural gas and NGLs in British Columbia varies depending
on the characteristics of the specific substance and can be as high as 27%, depending on factors such as whether the
gas is classified as conservation gas or non-conservation gas, the applicable reference price and select price.
Land Tenure
The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western
provinces. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases,
licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to
perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and
rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be
negotiated.
In response to COVID-19, the governments of Alberta and British Columbia have announced measures to extend or
continue Crown leases and permits that may have otherwise expired in the months following the implementation of
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pandemic response measures. In March 2020, the British Columbia Ministry of Energy, Mines and Low Carbon
Innovation announced that it was suspending posting requests and dispositions of petroleum and natural gas rights
until further notice due to COVID-19. In December 2020, the monthly tenure process was resumed.
Each of the provinces of Alberta and British Columbia has implemented legislation providing for the reversion to the
Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease
or license. On March 29, 2007, British Columbia expanded its policy of deep rights reversion for new leases to provide
for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of
their primary term.
Alberta also has a policy of “shallow rights reversion” which provides for the reversion to the Crown of mineral rights
to shallow, non-productive geological formations for all leases and licenses. For leases and licenses issued subsequent
to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or
intermediate term of the license.
Production and Operation Regulations
The oil and natural gas industry in Canada is highly regulated and subject to significant control by provincial
regulators. Regulatory approval is required for, among other things, the drilling of oil and natural gas wells,
construction and operations of facilities, the storage, injection and disposal of substances and the abandonment and
reclamation of well-sites. In order to conduct oil and gas operations and remain in good standing with the applicable
provincial regulator, Kelt must comply with applicable legislation, regulations, orders, directives and other directions
(all of which are subject to governmental oversight, review and revision). Compliance with such legislation,
regulations, orders, directives or other directions can be costly and a breach of the same may result in fines or other
sanctions.
Environmental Regulation
The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial
and federal legislation, all of which is subject to governmental review and revision. Such legislation provides for,
among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in
association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such
legislation sets out the requirements with respect to oilfield waste handling and storage, habitat production and the
satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such
legislation can require significant expenditures and a breach of such requirements may result in suspension or
revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material
fines and penalties. In addition to these specific, known requirements, future changes to environmental legislation,
including anticipated legislation for air pollution and greenhouse gas (“GHG”) emissions, may impose further
requirements on operators and other companies in the oil and natural gas industry.
Federal
On a Federal level and pursuant to the Prosperity Act (Canada), the Government of Canada amended or appealed
several pieces of federal environmental legislation and in addition, created a new federal environment assessment
regime. The changes to the environmental legislation under the Prosperity Act (Canada) are intended to provide for
more efficient and timely environmental assessments of projects that previously had been subject to overlapping
legislative jurisdiction.
On August 28, 2019, with the passing of Bill C-69, the CERA and the Impact Assessment Act (“IAA”) came into force
and the NEB Act and the Canadian Environmental Assessment Act, 2012 were repealed. In addition, the Impact
Assessment Agency of Canada (the “IA Agency”) replaced the Canadian Environmental Assessment Agency.
The enactment of the CERA and the IAA introduced a number of important changes to the regulation of federally
regulated major projects and their associated environmental assessments. The CERA separates the CER’s
administrative and adjudicative functions. A board of directors and a chief executive officer manage strategic,
administrative and policy considerations while adjudicative functions fall to independent commissioners. The CER
has jurisdiction over matters such as the environmental and economic regulation of pipelines, transmission
infrastructure and certain offshore renewable energy projects. In its adjudicative role, the CERA tasks the CER with
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reviewing applications for the development, construction and operation of many of these projects, culminating in their
eventual abandonment.
The IAA relies on a designated project list as a trigger for a federal assessment. Designated projects that may have
effects on matters within federal jurisdiction will generally require an impact assessment administered by the IA
Agency or, in the case of certain pipelines, a joint review panel comprised of members from the CER and the IAA.
The impact assessment requires consideration of the project’s potential adverse effects and the overall societal impact
that a project may have, both of which may include a consideration of, among other items, environmental, biophysical
and socio-economic factors, climate change, and impacts to Indigenous rights. It also requires an expanded public
interest assessment. Designated projects specific to the oil and gas industry include pipelines that require more than
75km of new right of way and pipelines located in national parks, large scale in situ oil sands projects not regulated
by provincial GHG emissions caps and certain refining, processing and storage facilities.
The federal government has stated that an objective of the legislative changes was to improve decision certainty and
turnaround times. Once a review or assessment is commenced under either the CERA or IAA, there are limits on the
amount of time the relevant regulatory authority will have to issue its report and recommendation. Designated projects
will go through a planning phase to determine the scope of the impact assessment, which the federal government has
stated should provide more certainty as to the length of the full review process. The Government of Alberta has
submitted a reference question to the Alberta Court of Appeal regarding the constitutionality of the IAA. This matter
remains before the courts.
On December 3, 2020, the Government of Canada tabled Bill C-15 (as defined below). Bill C-15 is the Government
of Canada’s response to requests to implement the United Nations Declaration of the Rights of Indigenous Peoples as
a framework for reconciliation in Canada. On June 21, 2021, the United Nations Declaration on the Rights of
Indigenous Peoples Act received Royal Assent and immediately came into force.
Alberta
The AER is the principal regulator responsible for all energy resource development in Alberta. It derives its authority
from the Responsible Energy Development Act and a number of related statutes including the Oil and Gas
Conservation Act (the “OGCA”), the Oil Sands Conservation Act, the Pipeline Act, and the Environmental Protection
and Enhancement Act. The AER is responsible for ensuring the safe, efficient, orderly and environmentally
responsible development of hydrocarbon resources, including allocating and conserving water resources, managing
public lands, and protecting the environment. The AER’s responsibilities exclude the functions of the Alberta Utilities
Commission and the Surface Rights Board, as well as the Alberta Ministry of Energy’s responsibility for mineral
tenure.
The Government of Alberta relies on regional planning to accomplish its resource development goals. Its approach to
natural resource management provides for engagement and consultation with stakeholders and the public and
examines the cumulative impacts of development on the environment and communities. While the AER is the primary
regulator for energy development, several other governmental departments and agencies may be involved in land use
issues, including the Alberta Ministry of Environment and Parks, the Alberta Ministry of Energy, the Aboriginal
Consultation Office and the Land Use Secretariat.
The Government of Alberta’s land-use policy in Alberta sets out an approach to manage public and private land use
and natural resource development in a manner that is consistent with the long-term economic, environmental and
social goals of the province. It calls for the development of seven region-specific land-use plans in order to manage
the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative
effects management approach into such plans.
The AER monitors seismic activity across Alberta to assess the risks associated with, and instances of, earthquakes
induced by hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppants and
additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate oil and
natural gas production. The Corporation routinely conduct hydraulic fracturing in its drilling and completion
programs. In recent years, hydraulic fracturing has been linked to increased seismicity in the areas in which hydraulic
fracturing takes place, prompting regulatory authorities to investigate the practice further.
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The AER has developed monitoring and reporting requirements that apply to all oil and natural gas producers working
in certain areas where the likelihood of an earthquake is higher, and implemented the requirements in Subsurface
Order Nos. 2, 6, and 7. The regions with seismic protocols in place are Fox Creek, Red Deer, and Brazeau (the
“Seismic Protocol Regions”). Oil and natural gas producers in each of the Seismic Protocol Regions are subject to a
“traffic light” reporting system that sets thresholds on the Richter scale of earthquake magnitude. The thresholds vary
among the Seismic Protocol Regions and trigger a sliding scale of obligations from the oil or natural gas producers
operating there. Such obligations range from no action required, to informing the AER and invoking an approved
response plan, to ceasing operations and informing the AER. The AER has the discretion to suspend operations while
it investigates following a seismic event until it has assessed the ongoing risk of earthquakes in a specific area and/or
may require the operator to update its response plan. The AER may extend these requirements to other areas of Alberta
if necessary, subject to the results of its ongoing province-wide monitoring.
British Columbia
In British Columbia, the Oil and Gas Activities Act (the “OGAA”) impacts conventional oil and gas producers, shale
gas producers, and other operators of oil and gas facilities in British Columbia. Under the OGAA, the British Columbia
Oil and Gas Commission (the “BC Commission”) has broad powers, particularly with respect to compliance and
enforcement and the setting of technical safety and operational standards for oil and gas activities. The Environmental
Protection and Management Regulation establishes the government’s environmental objectives for water, riparian
habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the BC
Commission to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity.
In addition, although not an exclusively environmental statute, the Petroleum and Natural Gas Act, in conjunction
with the OGAA requires proponents to obtain various approvals before undertaking exploration or production work,
such as geophysical licences, geophysical exploration project approvals, and permits for the exclusive right to do
geological work and geophysical exploration work, and well, test hole, and water-source well authorizations. Such
approvals are given subject to environmental considerations and licences and project approvals can be suspended or
cancelled for failure to comply with this legislation or its regulations.
An updated Environmental Assessment Act came into force on December 16, 2019. The amendments subject proposed
projects to an enhanced environmental review process similar in substance to the federal environmental assessment
process. The new environmental assessment process aims to enhance Indigenous engagement in the project approval
process with an emphasis on consensus-building, in alignment with British Columbia’s recent passage of Bill 41,
which affirmed and adopted the United Nations Declaration on the Rights of Indigenous Peoples. Simultaneously with
the enactment of the Environmental Assessment Act, the British Columbia Government enacted the accompanying
Reviewable Projects Regulation, which sets out the projects subject to the new regime. The “project list” captures
industrial, mining, energy, water management, waste disposal, transportation and other GHG intensive projects. In
conducting an environmental assessment, the Environmental Assessment Office will consider the environmental,
health, cultural, social and economic effects of a proposed project.
The extent and magnitude of any adverse impacts of changes to the legislation or policies on project development and
operations cannot be estimated at this time as uncertainty exists with respect to recommendations being considered or
to be developed. Increased environmental assessment obligations or transportation restrictions may create risk of
increased costs and project development delays.
Liability Management Rating Programs
Alberta
The AER administers a Liability Management Rating Program (the “AB LM Framework”) and the Liability
Management Rating Program (the “AB LMR Program”) to manage liability for most conventional upstream oil and
natural gas wells, facilities and pipelines in Alberta. The AER is in the process of replacing the AB LMR Program
with the AB LM Framework. This change was effected under key new AER directives in 2021. Broadly, the AB LM
Framework is intended to provide a more holistic approach to liability management in Alberta, as the AER found that
the more formulaic approach under the AB LMR Program did not necessarily indicate whether a company could meet
its liability obligations. New developments under the AB LM Framework include a new Licensee Capability
Assessment System (the “AB LCA”), a new Inventory Reduction Program (the “AB IR Program”), and a new Licensee
Management Program (the “AB LM Program”). Meanwhile, some programs under the AB LMR Program remain in
effect, including the Oilfield Waste Liability Program (the “AB OWL Program”), the Large Facility Liability
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Management Program (the “AB LF Program”) and elements of the Licensee Liability Rating Program (the “AB LLR
Program”). The mix between active programs under the AB LM Framework and the AB LMR Program highlights the
transitional and dynamic nature of liability management in Alberta. While the province is moving towards the AB LM
Framework and a more holistic approach to liability management, the AER has noted that this will be a gradual process
that will take time to complete. In the meantime, the AB LMR Program continues to play an important role in Alberta’s
liability management scheme.
Complementing the AB LM Framework and the AB LMR Program, Alberta’s OGCA establishes an orphan fund (the
“Orphan Fund”) to help pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included
in the AB LLR Program and the AB OWL Program if a licensee or working interest participant becomes insolvent or
is unable to meet its obligations. Licensees in the AB LLR Program and the AB OWL Program fund the Orphan Fund
through a levy administered by the AER. However, given the increase in orphaned oil and natural gas assets, the
Government of Alberta has loaned the Orphan Fund approximately $335 million to carry out abandonment and
reclamation work. In response to the COVID-19 pandemic, the Government of Alberta also covered $113 million in
levy payments that licensees would otherwise have owed to the Orphan Fund, corresponding to the levy payments due
for the first six months of the AER’s fiscal year. A separate orphan levy applies to persons holding licences subject to
the AB LF Program. Collectively, these programs are designed to minimize the risk to the Orphan Fund posed by the
unfunded liabilities of licensees and to prevent the taxpayers of Alberta from incurring costs to suspend, abandon,
remediate and reclaim wells, facilities or pipelines.
As a result of the Supreme Court of Canada’s decision in Orphan Well Association v Grant Thornton (also known as
the Redwater decision), receivers and trustees can no longer avoid the AER’s legislated authority to impose
abandonment orders against licensees or to require a licensee to pay a security deposit before approving a transfer
when such a licensee is subject to formal insolvency proceedings. This means that insolvent estates can no longer
disclaim assets that have reached the end of their productive lives (and therefore represent a net liability) in order to
deal primarily with the remaining productive and valuable assets without first satisfying any abandonment and
reclamation obligations associated with the insolvent estate’s assets. In April 2020, the Government of Alberta passed
Bill 12: The Liabilities Management Statutes Amendment Act. Bill 12 places the burden of a defunct licensees’
abandonment and reclamation obligations first on the defunct licensee’s working interest partners, and second, the
AER may order the Orphan Fund to assume care and custody and accelerate the clean-up of wells or sites which do
not have a responsible owner. These changes came into force in June 2020.
In response to the increase in orphaned crude oil and natural gas sites and the environmental risks associated therewith,
the AER has issued several bulletins and interim rule changes to govern the AER’s administration of its licensing and
liability management programs. For example, the AER amended its Directive 067: Eligibility Requirements for
Acquiring and Holding Energy Licences and Approvals (“Directive 067”), which deals with licensee eligibility to
operate wells and facilities, to require the provision of extensive corporate governance and shareholder information,
including whether any director and officer was a director or officer of an energy company that has been subject to
insolvency proceedings in the last five years. All transfers of well, facility and pipeline licences in the province are
subject to AER approval. As a condition of transferring existing AER licences, approvals and permits, all transfers
are now assessed on a non-routine basis and the AER now requires all transferees to demonstrate that they have an
LMR of 2.0 or higher immediately following the transfer, or to otherwise prove to the satisfaction of the AER that
they can meet their abandonment and reclamation obligations. However, amendments from April 2021 to Directive
067 expanded the criteria for assessing licensee eligibility. Notably, the recent amendments increase requirements for
financial disclosure, detail new requirements for when a licensee poses an “unreasonable risk” of orphaning assets,
and adds additional general requirements for maintaining eligibility.
Alongside changes to Directive 067, the AER also introduced Directive 088: Licensee Life-Cycle Management
(“Directive 088”) in December 2021 under the AB LM Framework. Directive 088 replaces, to an extent, the AB LLR
Program with the AB LCA. Whereas the AB LLR Program previously assessed a licensee based on a liability rating
determined by the ratio of a licensee’s deemed asset value relative to the deemed liability value of its oil and gas wells
and facilities, the AB LCA now considers a wider variety of factors and is intended to be a more comprehensive
assessment of corporate health. Such factors are wide reaching and include: (i) a licensee’s financial health; (ii) its
established total magnitude of liabilities, (iii) the remaining lifespan of its mineral resources; (iv) the management of
its operations; (v) the rate of closure activities for its liabilities; and (vi) and its compliance with administrative and
regulatory requirements. These various factors then feed into a broader holistic assessment of a licensee under the AB
LM Framework. In turn, that holistic assessment provides the basis for assessing risk posed by licence transfers, as
well as any security deposit that the AER may require from a licensee in the event that the regulator deems a licensee
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at risk of not being able to meet its liability obligations. However, the liability management rating under the LLR
Program is still in effect for other liability management programs such as the AB OWL Program and the AB LF
Program, and will remain in effect until a broadened scope of Directive 088 is phased in over time.
In addition to the AB LCA, Directive 088 also implemented other new liability management programs under the AB
LM Framework. These include the AB LM Program and the AB IR Program. Under the AB LM Program the AER
will continuously monitor licensees over the life-cycle of a project. If, under the AB LM Program, the AER identifies
a licensee as high risk, the regulator may employ various tools to ensure that a licensee meets its regulatory and liability
obligations. In addition, under the AB IR Program the AER sets industry wide spending targets for abandonment and
reclamation activities. Licensees are then assigned a mandatory licensee specific target based on the licensee’s
proportion of provincial inactive liabilities and the licensee’s level of financial distress. Certain licensees may also
elect to provide the AER with a security deposit in place of their closure spend target.
The AER has also implemented the Inactive Well Compliance Program (the “IWCP”) to address the growing
inventory of inactive wells in Alberta and to increase the AER’s surveillance and compliance efforts under Directive
013: Suspension Requirements for Wells (“Directive 013”). The IWCP applies to all inactive wells that are
noncompliant with Directive 013 as of April 1, 2015. The objective is to bring all inactive noncompliant wells under
the IWCP into compliance with the requirements of Directive 013 within five years. As of April 1, 2015, each licensee
is required to bring 20% of its inactive wells into compliance every year, either by reactivating or suspending the wells
in accordance with Directive 013 or by abandoning them in accordance with Directive 020: Well Abandonment. The
compliance deadline for the final year of the IWCP was extended from April 1, 2020 to September 1, 2020 and was
concluded in March of 2021.
The Government of Alberta followed the announcement of the AB LM Framework with amendments to the Oil and
Gas Conservation Rules and the Pipeline Rules in late 2020. The changes to these rules fall into three principal
categories: (i) they introduce “closure” as a defined term, which captures both abandonment and reclamation; (ii) they
expand the AER’s authority to initiate and supervise closure; and (iii) they permit qualifying third parties on whose
property wells or facilities are located to request that licensees prepare a closure plan.
As part of its strategy to encourage the decommissioning, remediation and reclamation of inactive or marginal crude
oil and natural gas infrastructure, the AER announced a voluntary area-based closure (“ABC”) program in 2018. The
ABC program is designed to reduce the cost of abandonment and reclamation operations though industry collaboration
and economies of scale. Participants seeking to participate in the program must commit to an inactive liability
reduction target to be met through closure work of inactive assets.
British Columbia
In British Columbia, the BC Commission implements the Liability Management Rating Program (the “BC LMR
Program”), designed to manage public liability exposure related to oil and gas activities by ensuring that permit
holders carry the financial risks and regulatory responsibility of their operations through to regulatory closure. Under
the BC LMR Program, the BC Commission determines the required security deposits for permit holders under the
OGAA. The LMR is the ratio of a permit holder’s deemed assets to deemed liabilities. Permit holders whose deemed
liabilities exceed deemed assets will be considered high risk and reviewed for a security deposit. Permit holders who
fail to submit the required security deposit within the allotted timeframe may be in non-compliance with the OGAA.
The BC Commission has indicated that it will move away from the BC LMR Program and move towards a more
holistic assessment under the new Permittee Capability Assessment program (the “BC PCA”). The BC PCA will
include an evaluation of more than only a permittee’s ratio of liabilities to assets. However, details regarding the BC
PCA remain forthcoming. The BC OGC has indicated that the BC PCA will be implemented by April 2022.
As a result of certain amendments to the OGAA, on April 1, 2019 a liability-based levy paid to the Orphan Site
Reclamation Fund (“OSRF”) replaced the orphan site reclamation fund tax paid by permit holders. Similar to
Alberta’s Orphan Fund, the OSRF is an industry-funded program created to address the abandonment and reclamation
costs for orphan sites. Permit holders are required to pay their proportionate share of the regulated amount of the levy,
calculated using each permit holder’s proportionate share of the total liabilities of all permit holders required to
contribute to the fund. The OGAA permits the BC Commission to impose more than one levy in a given calendar
year.
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Effective May 31, 2019, the Dormancy and Shutdown Regulation (the “Dormancy Regulation”) establishes the first
set of legally imposed timelines for the restoration of oil and natural gas wells in Western Canada. The Dormancy
Regulation classifies different sites based on activity levels associated with the well(s) on each site, with a goal of
ensuring that 100% of currently dormant sites are reclaimed by 2036 with additional regulated timelines for sites that
become dormant between 2019 and 2023 or become dormant after 2024. A permit holder will have varying reporting,
decommissioning, remediation and reclamation obligations that depend on the classification of its sites. Any permit
holder that has a dormant site in its portfolio must develop and submit an annual work plan to the BC Commission,
outlining its decommissioning and restoration activities for each calendar year. The permit holder must also prepare
and submit a retrospective annual report within 60 days of the end of the calendar year in which it conducted the work
outlined in an annual work plan.
The Government of British Columbia passed amendments to the Oil and Gas Activities Act under the Miscellaneous
Statutes Amendment Act (No.2) in October 2021. These amendments allow the BC Commission to grant exemptions
for strict compliance with the requirements of the Dormancy Regulation. In turn, this may mean that a permit holder
can, with approval, depart from the regulated timelines set under the Dormancy Regulation. The relevant amendments
which provide the BC Commission with the power to grant these exemptions came into force on October 28, 2021.
Federal and Provincial Support for Liability Management
As part of an announcement of federal relief for Canada’s petroleum and natural gas industry in response to COVID-
19, the federal government pledged $1.72 billion to clean up orphan and inactive wells in Alberta, Saskatchewan and
British Columbia in May 2020. These funds were administered by regulatory authorities in each province and
disbursed through various provincial programs. The majority of these funds have now been allocated and disbursed.
Climate Change Regulation
Federal
Canada has been a signatory to the United Nations Framework Convention on Climate Change (the “UNFCCC”)
since 1992. Since its inception, the UNFCCC has instigated numerous policy experiments with respect to climate
governance. On April 22, 2016, 197 countries signed the Paris Agreement, committing to prevent global temperatures
from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than
1.5° Celsius. On January 20, 2021, President Biden of the United States signed an executive order to rejoin the Paris
Agreement. To date, 189 of the 197 parties to the UNFCCC have ratified the Paris Agreement, including Canada.
In 2016, the Government of Canada has pledged to cut its emissions by 30% from 2005 levels by 2030. In 2021,
Canada updated its original commitment by pledging to reduce emissions by 40-45% below 2005 levels by 2030, and
to net-zero by 2050.
During the course of the 2021 United Nations Climate Change Conference in Glasgow, Scotland, Canada’s Prime
Minister Justin Trudeau made several pledges aimed at reducing Canada’s GHG emissions and environmental impact,
including: (i) reducing methane emissions in the oil and gas sector to 75% of 2012 levels by 2030; (ii) ceasing export
of thermal coal by 2030; (iii) imposing a cap on emissions from the oil and gas sector; (iv) halting direct public funding
to the global fossil fuel sector by the end of 2022; and (v) committing that all new vehicles sold in the country will be
zero-emission on or before 2040.
The Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change in 2016,
setting out a plan to meet the federal government’s 2030 emissions reduction targets. On June 21, 2018, the federal
government enacted the Greenhouse Gas Pollution Pricing Act (the “GGPPA”), which came into force on January 1,
2019. This regime has two parts: an output-based pricing system for large industry and a regulatory fuel charge
imposing an initial price of $20/tonne of carbon dioxide equivalent (“CO2e”) emissions. This system applies in
provinces and territories that request it and in those that do not have their own emissions pricing systems in place that
meet the federal standards. This ensures that there is a uniform price on emissions across the country. Originally under
current federal plans, this price will escalate by $10 per year until it reaches a price of $50/tonne of CO2e in 2022. On
December 11, 2020, however, the federal government announced its intention to continue the annual price increases
beyond 2022, such that, commencing in 2023, the benchmark price per tonne of CO2e will increase by $15 per year
until it reaches $170/tonne of CO2e in 2030. Starting April 1, 2022, the minimum price permissible under the GGPPA
is $50/tonne of CO2e. In addition, on March 5, 2021, the federal government introduced for comment the Greenhouse
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Gas Offset Credit System Regulations (Canada) (the “Federal Offset Credit Regulations”). The proposed Federal
Offset Credit Regulations are intended to establish a regulatory framework to allow certain kinds of projects to
generate and sell offset credits for use in the federal OBPS. The final Federal Offset Credit Regulations are currently
targeted for publication in mid-2022.
Alberta, Saskatchewan, and Ontario referred the constitutionality of the GGPPA to their respective Courts of Appeal.
In the Saskatchewan and Ontario references, the appellate Courts found the GGPPA to be constitutional; the Alberta
Court of Appeal determined that the GGPPA is unconstitutional. All three judgments were appealed to the Supreme
Court of Canada. The Supreme Court of Canada confirmed the constitutional validity of the GGPPA in a judgment
released on March 25, 2021.
On April 26, 2018, the federal government passed the Regulations Respecting Reduction in the Release of Methane
and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the “Federal Methane Regulations”).
The Federal Methane Regulations seek to reduce emissions of methane from the crude oil and natural gas industry,
and came into force on January 1, 2020. By introducing a number of new control measures, the Federal Methane
Regulations aim to reduce unintentional leaks and intentional venting of methane, as well as ensuring that crude oil
and natural gas operations use low-emission equipment and processes. Among other things, the Federal Methane
Regulations limit how much methane upstream oil and natural gas facilities are permitted to vent. These facilities
would need to capture the gas and either re-use it, re-inject it, send it to a sales pipeline, or route it to a flare. In
addition, in provinces other than Alberta and British Columbia (which already regulate such activities); well
completions by hydraulic fracturing would be required to conserve or destroy gas instead of venting. The federal
government anticipates that these actions will reduce annual GHG emissions by about 20 megatonnes by 2030.
As part of its efforts to provide relief to Canada’s oil and gas industry in light of the COVID-19 pandemic, the federal
government announced a $750 million Emissions Reduction Fund intended to support pollution reduction initiatives,
including methane. Funds disbursed through this program will primarily take the form of repayable contributions to
onshore and offshore oil and gas firms. Of the $750 million in funding, $675 million was allocated to the Onshore
Deployment Program, while $75 million was dedicated to the Offshore Deployment Program and the Offshore RD&D
(research, development and demonstration) Program. Natural Resources Canada expects that all funding for onshore
projects will be allocated by March 2022, while funding for offshore projects will be allocated by March 2023.
To complement carbon pricing, a Clean Fuel Standard with the objective of achieving annual reductions of 30 Mt of
GHG emissions by 2030 is being developed by the federal government. The standard would require reductions in the
carbon footprint of the fuels supplied in Canada, based on life cycle analysis. The approach will not differentiate
between crude oil types produced in or imported into Canada. This standard is expected to apply to a broad suite of
fuels used in transportation, industry, homes and buildings. It is expected that the applicable regulations will come
into force in December 2022.
In the November 23, 2021 Speech from the Throne, the federal government restated its commitment to achieve net-
zero emission by 2050. In pursuit of this objective, the government’s proposed actions include: (i) moving to cap and
cut oil and gas sector emissions; (ii) investing in public transit and mandating the sale of zero-emission vehicles; (iii)
increasing the federally imposed price on pollution; (iv) investing in the production of cleaner steel, aluminum,
building products, cars, and planes; (v) addressing the loss of biodiversity by continuing to strengthen partnerships
with First Nations, Inuit, and Métis, to protect nature and the traditional knowledge of those groups; (vi) creating a
Canada Water Agency to safeguard water as a natural resource and support Canadian farmers; (vii) strengthening
action to prevent and prepare for floods, wildfires, droughts, coastline erosion, and other extreme weather worsened
by climate change; and (viii) helping build back communities impacted by extreme weather events through the
development of Canada’s first-ever National Adaptation Strategy.
The Canadian Net-Zero Emissions Accountability Act (the “CNEAA”) received royal assent on June 29, 2021, and
came into force on the same day. The CNEAA binds the Government of Canada to a process intended to help Canada
achieve net-zero emissions by 2050. It establishes rolling five-year emissions-reduction targets and requires the
government to develop plans to reach each target and support these efforts by creating a Net-Zero Advisory Body.
The CNEAA also requires the federal government to publish annual reports that describe how departments and crown
corporations are considering the financial risks and opportunities of climate change in their decision-making. A
comprehensive review of the CNEAA is required every five years from the date the CNEAA came into force.
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The Government of Canada is also in the midst of developing a carbon capture utilization and storage (“CCUS”)
strategy. CCUS is a technology that captures carbon dioxide from facilities, including industrial or power applications,
or directly from the atmosphere. The captured carbon dioxide is then compressed and transported for permanent
storage in underground geological formations or used to make new products such as concrete. The federal government
has indicated that urgent steps are necessary to ramp up CCUS in Canada, as this will be a critical element of the plan
to reach net-zero by 2050.
In general, there is uncertainty with regard to the impact of federal or provincial climate change and environmental
laws and regulations, as it is currently not possible to predict the extent of future requirements. Any new laws and
regulations, or additional requirements to existing laws and regulations, could have a material impact on Kelt’s
operations and cash flow.
Alberta
On November 22, 2015, the Government of Alberta introduced a Climate Leadership Plan (the “CLP”). Under this
strategy, the Climate Leadership Act (the “CLA”) came into force on January 1, 2017 and established a fuel charge
intended to first outstrip and subsequently keep pace with the federal price. On December 4, 2019, the federal
government approved Alberta’s proposed Technology Innovation and Emissions Reduction (“TIER”) regulation, so
the regulation of emissions from heavy industry remains subject to provincial regulation, while the federal fuel charge
still applies. The TIER regulation came into effect on January 1, 2020.
The TIER regulation applies to industrywide to emitters that emit more than 100,000 tonnes of CO2e per year in 2016
or any subsequent year. The 2020 target for most TIER-regulated facilities is to reduce emissions intensity by 10% as
measured against that facility’s individual benchmark (which is, generally, its average emissions intensity during the
period from 2013 to 2015), with a further 1% reduction for each subsequent year. The facility-specific benchmark
does not apply to all facilities. Certain facilities, such as those in the electricity sector, are compared against the good-
as-best gas standard, which measures against the emissions produced by the cleanest natural gas-fired generation
system. Similarly, for facilities that have already made substantial headway in reducing their emissions, a different
“high-performance” benchmark is available to ensure that the cost of ongoing compliance takes this into account. The
TIER regulation targets emissions intensity rather than total emissions. Under the TIER regulation, facilities in high-
emitting sectors can opt-in to the program despite the fact that they do not meet the 100,000 tonne threshold. A facility
can opt-in to TIER regulation if it competes directly against another TIER-regulated facility or if it has annual CO2e
emissions that exceed 10,000 tonnes per year and belongs to an emissions-intensive or trade exposed sector with
international competition. In addition, the owner of two or more “conventional oil and gas facilities” may apply to
have those facilities regulated under the TIER regulation. To encourage compliance with the emissions intensity
reduction targets, TIER-regulated facilities must provide annual compliance reports and facilities that are unable to
achieve their targets may either purchase credits from other facilities, purchase carbon offsets, or pay a levy to the
Government of Alberta.
On September 1, 2020, the Government of Alberta announced $750 million in spending from the TIER fund to support
projects that help industries reduce their carbon emissions. Such projects include CCUS, energy efficiency, and
increased methane management initiatives. An additional $176 million in spending from the TIER fund was
announced for similar GHG reduction projects on November 1, 2021.
The Government of Alberta previously signaled its intention through the CLP to implement regulations that would
lower annual methane emissions by 45% by 2025. Pursuant to this goal, the Government of Alberta enacted the
Methane Emission Reduction Regulation (the “Alberta Methane Regulations”) on January 1, 2020, and the AER
simultaneously released an updated edition of Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and
Venting (“Directive 060”). The release of Directive 060 complements a previously released update to Directive 017:
Measurement Requirements for Oil and Gas Operations that took effect in December 2018. Together, these new
Directives represent Alberta’s first step toward achieving its 2025 goal, as outlined in the Alberta Methane
Regulations. In November 2020, the Government of Canada and the Government of Alberta announced an equivalency
agreement regarding the reduction of methane emissions such that the Federal Methane Regulations will not apply in
Alberta.
Alberta is also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and
storage technology across industrial sectors. Alberta has committed $1.24 billion over 15 years to fund two large-scale
carbon capture and storage projects that will begin commercializing the technology on the scale needed to be
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successful. On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes
Amendment Act, 2010. It deemed the pore space underlying all land in Alberta to be, and to have always been, the
property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the
Crown, subject to the satisfaction of certain conditions.
British Columbia
British Columbia enacted a revenue-neutral carbon tax that took effect July 1, 2008. The tax is consumption-based
and applied at the time of retail sale or consumption of virtually all fossil fuels purchased or used in British Columbia.
In order to make the tax revenue-neutral, British Columbia has implemented tax credits and reductions in order to
offset the tax revenues that the Government of British Columbia would otherwise receive from the tax. The fuel charge
is currently set at $45/tonne of CO2e. The charge will increase to $50/tonne of CO2e on April 1, 2022 and will continue
to increase in line with the GGPPA minimum charge. Federal carbon pricing mechanisms are not currently in force in
British Columbia, as the province’s programs currently meet or exceed the federal benchmark stringency
requirements.
On January 1, 2016, the Greenhouse Gas Industrial Reporting and Control Act (the “GGIRCA”) and its associated
regulations that came into force. The GGIRCA sets out benchmarked performance standards for different industrial
facilities and sectors, provides for emissions offsets through the purchase of emission credits or emission offsetting
projects, among other measures.
On August 19, 2016, the Government of British Columbia unveiled its Climate Leadership Plan with a goal to reduce
net annual GHG emissions by up to 25 million tonnes below current forecasts by 2050, and reaffirmed that it will
achieve its 2050 target of an 80% reduction in emissions from 2007 levels.
On December 5, 2018, the Government of British Columbia announced an updated clean energy plan, “CleanBC”,
which seeks to ensure that British Columbia achieves 75% of its GHG emissions reduction target by 2030. The
CleanBC plan includes a number of strategies targeting the industrial, transportation construction, and waste sectors
of the British Columbia economy. Key initiatives include: (i) increasing the generation of electricity from clean and
renewable energy sources; (ii) imposing a 15% renewable content requirement in natural gas by 2030; (iii) requiring
fuel suppliers to reduce the carbon intensity of diesel and gasoline by 20% by 2030; (iv) investing in the electrification
of crude oil and natural gas production; (v) reducing 45% of methane emissions associated with natural gas production;
and (vi) incentivizing the adoption of zero- emissions vehicles. Complementing its CleanBC plan, on March 26, 2021,
the Government of British Columbia announced a number of sector-specific emissions reduction targets, established
with reference to 2007 emissions levels, that it aims to achieve by 2030, including reduction targets of 27-32% for the
transportation sector, 38-43% for industry and 33-38% for oil and gas.
The Government of British Columbia established the CleanBC Industry Fund in 2019 to support clean industry
development in the province. The fund uses a portion of carbon tax revenue paid by large emitters to invest in projects
aimed at reducing greenhouse gas emissions. In March 2021, the Government of British Columbia temporarily
increased the provincial share of funding to up to 90% of project costs with a cap of $25 million per project. As of
November 2021, the CleanBC Industry Fund had invested $43 million in 32 projects across British Columbia.
In October 2021, the Government of British Columbia announced a more ambitious climate change plan called the
CleanBC Roadmap to 2030 (the “CleanBC Roadmap”), aimed at helping British Columbia achieve its 2030 emission
reduction targets established under the CleanBC plan. The CleanBC Roadmap includes plans for, among other things,
laws requiring 90% of new passenger vehicles sold in the province to be zero-emission by 2030, all new buildings to
be zero-carbon beginning in 2030, the electrification of public transit and ferries, and for increased support for clean
hydrogen and negative emissions technology. Further, the CleanBC Roadmap plans to increase carbon taxation in the
province to meet or exceed the federal GGPPA benchmark.
In January 2020, the BC Commission implemented a series of amendments to the British Columbia Drilling and
Production Regulation that will require facility and well permit holders to, among other things, reduce natural gas
leaks and curb monthly natural gas emissions from their equipment and operations. In November 2020, the
Government of Canada and the Government of British Columbia announced that they had finalized an equivalency
agreement regarding the reduction of methane emissions such that the Federal Methane Regulations will not apply in
British Columbia.
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Indigenous Rights
Constitutionally mandated government-led consultation with and, if applicable, accommodation of, Indigenous groups
impacted by regulated industrial activity, as well as proponent-led consultation and accommodation or benefit sharing
initiatives, play an increasingly important role in the Western Canadian oil and gas industry. In addition, Canada is a
signatory to the UNDRIP and the principles set forth therein may continue to influence the role of Indigenous
engagement in the development of the oil and gas industry in Western Canada. For example, in November 2019, the
Declaration on the Rights of Indigenous Peoples Act (“DRIPA”) became law in British Columbia. The DRIPA aims
to align British Columbia’s laws with UNDRIP. In June 2021, the United Nations Declaration on the Rights of
Indigenous Peoples Act (“UNDRIP Act”) came into force in Canada. Similar to British Columbia’s DRIPA, the
UNDRIP Act requires the Government of Canada to take all measures necessary to ensure the laws of Canada are
consistent with the principles of UNDRIP and to implement an action plan to address UNDRIP’s objectives.
Continued development of common law precedent regarding existing laws relating to Indigenous consultation and
accommodation as well as the adoption of new laws such as DRIPA and UNDRIP Act are expected to continue to add
uncertainty to the ability of entities operating in the Canadian oil and gas industry to execute on major resource
development and infrastructure projects, including, among other projects, pipelines. The Government of Canada has
expressed that implementation of the UNDRIP Act has the potential to make meaningful change in how Indigenous
peoples collaborate in impact assessment moving forward, but has confirmed that the current IAA already establishes
a framework that aligns with UNDRIP and does not need to be changed in light of the UNDRIP Act.
On June 29, 2021, the British Columbia Supreme Court issued the Blueberry Decision with respect to a claim brought
forth by the BRFN against the province of British Columbia regarding the cumulative impact of industrial
development within the BRFN treaty claim area. The Blueberry Decision found that the Province of British Columbia
breached the Treaty 8 rights of the BRFN by allowing extensive industrial development on the BRFN’s traditional
territory without first assessing the cumulative impacts of this development on the ability of the members of the BRFN
to exercise their Treaty 8 rights to hunt, fish, and trap on their traditional territory. The Blueberry Decision calls for
the province of British Columbia to pause some development in the BRFN traditional area pending the results of an
investigation into the cumulative impacts of industrial development in the BFN’s traditional territory. The Blueberry
Decision gave six months for the Government of British Columbia and the BRFN to negotiate changes to the
regulatory regime that recognizes and respects treaty rights.
On October 7, 2021, the Government of British Columbia and the BRFN announced they reached a first step in the
initial agreement in developing land management processes on the BRFN traditional territory. As part of this
agreement, a number of forestry and oil and gas projects, which were permitted or authorized prior to the Blueberry
Decision, would continue to proceed. The announcement also states that the Province of British Columbia and BRFN
are working to finalize an interim approach for reviewing new natural resource activities that balance Treaty 8 rights,
the economy and the environment.
DIVIDEND POLICY
There are no restrictions in Kelt’s articles or elsewhere which could prevent Kelt from paying dividends. It is not
currently contemplated that any dividends will be paid on any shares of Kelt in the immediate future, as it is anticipated
that all available funds will be invested to finance the growth of Kelt’s business. The Board of Directors will determine
if, and when, dividends will be declared and paid in the future from funds properly applicable to the payment of
dividends based on Kelt’s financial position at the relevant time. Any decision to pay dividends on any shares of Kelt
will be made by the Board of Directors on the basis of Kelt’s earnings, special dividends resulting from asset
dispositions, financial requirements and other factors existing at such future time, including, but not limited to,
commodity prices, production levels, capital expenditure requirements, debt service requirements, if any, operating
costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by the
ABCA for the declaration and payment of dividends.
DESCRIPTION OF SHARE CAPITAL
Kelt is authorized to issue an unlimited number of Common Shares and an unlimited number of Preferred Shares, of
which 189,338,981 Common Shares and no Preferred Shares are issued and outstanding as at the date of this Annual
Information Form. See “Prior Sales” in this Annual Information Form.
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The following is a description of the rights, privileges, restrictions and conditions attaching to the Common Shares
and the Preferred Shares.
Common Shares
The holders of Common Shares are entitled to receive notice of and to attend at and to vote one vote per Common
Share at meetings of shareholders, to receive dividends declared on the Common Shares, subject to the rights of the
holders of shares ranking prior to the Common Shares and to receive pro rata the remaining property upon dissolution
in equal rank with the holders of other Common Shares.
Preferred Shares
The Preferred Shares may be issued in one or more series, each series consisting of a number of Preferred Shares as
determined by the Board of Directors who may also fix the designations, rights, privileges, restrictions and conditions
attaching to the shares of each series of Preferred Shares. The Preferred Shares of each series shall, with respect to
payment of dividends and distributions of assets in the event of liquidation, dissolution or winding-up of Kelt, whether
voluntary or involuntary, or any other distribution of the assets of Kelt among its shareholders for the purpose of
winding-up its affairs, rank equally with the Preferred Shares of every other series and shall be entitled to preference
over the Common Shares, and the shares of any other class ranking junior to the Preferred Shares.
Trading Price and Volume
MARKET FOR SECURITIES
The following table sets forth the reported high and low sales prices (which are not necessarily the closing prices) and
the trading volumes for the Common Shares of Kelt on the TSX as reported by sources Kelt believes to be reliable for
the periods indicated:
Date
2021
January
February
March
April
May
June
July
August
September
October
November
December
2022
January
February
March 1-8
Price Range ($)
High
Low
Trading Volume
2.24
2.76
3.19
2.88
3.26
3.62
3.57
3.49
4.85
5.28
5.44
4.86
5.79
5.83
6.05
1.74
1.77
2.45
2.35
2.69
3.16
2.71
2.83
3.29
4.53
4.23
4.00
4.82
5.24
5.50
20,923,336
23,482,233
20,898,517
10,596,774
10,750,665
9,339,017
8,646,597
7,524,724
11,651,635
9,843,986
14,372,811
8,770,528
11,929,875
13,588,290
4,221,132
PRIOR SALES
The following table sets forth, for each class of securities of the Corporation that is outstanding but not listed or quoted
on a marketplace, the price at which securities of the class have been issued during the financial year ended December
31, 2021 and the number of securities of the class issued at that price and the date on which the securities were issued.
Class of Securities
Options
Options
Issue Price
or Exercise Price
$
$2.72
$2.59
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Number of
Securities Issued
2,460,000
22,000
Date of Issue
March 24, 2021
April 19, 2021
Class of Securities
Issue Price
or Exercise Price
$
Number of
Securities Issued
Date of Issue
Options
Options
Options
Options
Options
Options
Options
RSUs
RSUs
RSUs
RSUs
RSUs
RSUs
$3.45
$3.27
$3.33
$3.96
$4.92
$5.01
$5.04
$2.72
$2.59
$3.27
$3.96
$5.01
$5.04
36,000
10,000
10,000
75,000
10,000
10,000
8,500
657,000
7,500
3,000
35,000
3,000
3,000
July 1, 2021
July 15, 2021
September 1, 2021
September 16, 2021
October 18, 2021
October 20, 2021
November 17, 2021
March 24, 2021
April 19, 2021
July 15, 2021
September 16, 2021
October 20, 2021
November 17, 2021
As at the date of this Annual Information Form, the Corporation has 10,301,707 Options and 751,500 RSUs
outstanding.
ESCROWED SECURITIES
As at the date of this Annual Information Form, to the knowledge of the Corporation, no securities of any class of Kelt
are held in escrow or are subject to a contractual restriction on transfer.
DIRECTORS AND OFFICERS
The following table provides the name, province and country of residence, positions held with Kelt and principal
occupation during the preceding five years of each of the current directors and executive officers of Kelt.
Name, Province and
Country of Residence
Douglas J. Errico
Alberta, Canada
Alan G. Franks
Alberta, Canada
David Gillis
Alberta, Canada
Offices Held and Time as
Director or Officer
Senior Vice President, Land &
Corporate Development since
October 22, 2012
Vice President, Production
since October 22, 2012
Vice President, Finance since
April, 2018
Bruce D. Gigg
Alberta, Canada
Vice President, Engineering
since March 11, 2016
Geraldine L.
Greenall(1)(4)(5)(6)
Alberta, Canada
Director since December 14,
2017
William C. Guinan(3)(7)
Alberta, Canada
Sadiq H. Lalani(8)
Alberta, Canada
Louise K. Lee
Alberta, Canada
Director since October 22,
2012
Vice President and Chief
Financial Officer since October
22, 2012
Corporate Secretary since
November 9, 2020
Principal Occupation During the
Past 5 Years
Vice President, Land of Kelt since November 9, 2020 and prior
thereto Vice President, Land of Kelt since October 22, 2012.
Prior thereto, Landman and then Senior Landman with Celtic
from September 2005 to February 2013.
Vice President, Production of Kelt. Prior thereto, Vice
President, Operations of Celtic from December 2002 to
February 2013.
Vice President, Finance of Kelt. Prior thereto, Executive Vice
President and Chief Financial Officer of Cequence Energy Ltd.
Prior thereto, Vice President, Finance and Chief Financial
Officer of Cequence Energy Ltd. from July 2009 to March 2017.
Vice President, Engineering of Kelt. Prior thereto, President of
Giggajoule Energy Inc. from October 2014 to March 2016.
Prior thereto Team Lead at NuVista Energy Ltd. from April
2005 to October 2014.
Chief Financial Officer of Spartan Delta Corp., a publicly listed
exploration and production corporation. Prior thereto, Chief
Financial Officer of Camber Capital Corp. (formerly Kyklopes
Capital Management Ltd.), an
investment management
corporation, from May 2011 to December 2019.
Retired. Partner with Borden Ladner Gervais LLP until
December 2020.
Vice President and Chief Financial Officer of Kelt. Prior
thereto, Vice President, Finance and Chief Financial Officer of
Celtic from October 2002 to February 2013.
Partner with Borden Ladner Gervais LLP.
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Name, Province and
Country of Residence
Douglas O. MacArthur
Alberta, Canada
Patrick W.G. Miles
Alberta, Canada
Michael R. Shea(2)(4)(5)
Alberta, Canada
Neil G. Sinclair(1)(2)(3)(5)
British Columbia, Canada
Offices Held and Time as
Director or Officer
Vice President, Operations
since October 22, 2012
Vice President, Exploration
since October 22, 2012
Director since April 18, 2018
Principal Occupation During the
Past 5 Years
Vice President, Operations of Kelt. Prior thereto, Operations
Manager with Celtic from January 2007 to February 2013.
Vice President, Exploration of Kelt. Prior thereto, Geology
Consultant with Celtic from November 2009 to February 2013.
Retired Businessman since February 2013.
Director since October 22,
2012
Carol Van Brunschot
Alberta, Canada
Vice President, Marketing
since July 1, 2018.
Janet Vellutini(1)(2)(4)
David J. Wilson(3)
Alberta, Canada
Director since July 1, 2021
President, Chief Executive
Officer and Director since
October 11, 2012
President of Sinson Investments Ltd., a private British Columbia
corporation engaged in property development, from 1973 to the
present.
Vice President, Marketing of Kelt. Prior thereto, Manager,
Marketing of Kelt from August 2016 to July 2018. Prior thereto
President of 1912420 Alberta Ltd. from May 2014 to July 2016.
Prior thereto, Director of Producer Services at BP Canada.
Retired Businesswomen since June 2021.
President and Chief Executive Officer of Kelt. Prior thereto,
President and Chief Executive Officer of Celtic from September
2002 to February 2013.
Notes:
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Member of the Audit Committee.
Member of the Compensation Committee.
Member of the Health, Safety and Environment Committee.
Member of the Reserves Committee.
Member of the Nominating Committee.
Lead Director.
Board Chair.
On March 11, 2016 Mr. Lalani resigned as Vice President, Finance and was appointed Vice President of Kelt and at all times since
October 22, 2012 Mr. Lalani has held the position of Chief Financial Officer of Kelt.
On November 9, 2020, Mr. Errico was appointed Senior Vice President, Land & Corporate Development and prior thereto, was Vice
President, Land since October 22, 2012.
Each of the directors of Kelt will hold office until the first annual meeting of the holders of Common Shares or until
his successor is duly elected or appointed, unless his office is earlier vacated in accordance with Kelt’s articles or by-
laws.
As at the date of this Annual Information Form, the current directors and officers of Kelt, as a group, beneficially
owned, or controlled or directed, directly or indirectly, an aggregate of 34.2 million Common Shares, representing
approximately 18% of the issued and outstanding Common Shares. The information as to the number of Common
Shares beneficially owned, or controlled or directed, not being within the knowledge of the Corporation, has been
furnished by the respective directors and officers of the Corporation individually.
Corporate Cease Trade Orders
None of the directors or executive officers of Kelt is or has been, within the 10 years prior to the date of this Annual
Information Form, a director, chief executive officer or chief financial officer of any company (including Kelt) that:
(i) was the subject of a cease trade or similar order or an order that denied the relevant company access to any
exemption under securities legislation, that was in effect for a period of more than 30 consecutive days that was issued
while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial
officer; or (ii) was subject to a cease trade or similar order or an order that denied the relevant issuer access to any
exemption under securities legislation, for a period of more than 30 consecutive days, that was issued after the director
or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from
an event that occurred while that person was acting in the capacity as a director, chief executive officer or chief
financial officer.
Bankruptcies
None of the directors, executive officers or securityholders holding a sufficient number of securities of Kelt to affect
materially the control of Kelt is or has, within the 10 years prior to the date of this Annual Information Form, been a
director or executive officer of any company (including Kelt) that, while such person was acting in that capacity, or
within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation
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relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with
creditors or had a receiver, receiver manager or trustee appointed to hold its assets.
In addition, none of the directors, executive officers or securityholders holding a sufficient number of securities of
Kelt to affect materially the control of Kelt has, within the 10 years prior to the date of this Annual Information Form,
become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to
or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee
appointed to hold the assets of the director, executive officer or securityholder.
Penalties or Sanctions
None of the directors, executive officers or securityholders holding a sufficient number of securities of Kelt to affect
materially the control of Kelt has been subject to: (i) any penalties or sanctions imposed by a court relating to securities
legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory
authority; or (ii) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered
important to a reasonable investor in making an investment decision.
Conflicts of Interest
There are potential conflicts of interest to which the directors and officers of Kelt may become subject in connection
with the operations of Kelt. In particular, certain directors and officers of Kelt are involved in managerial or director
positions with other oil and gas companies whose operations may, from time to time, be in direct competition with
those of Kelt or with entities which may, provide financing to, or make equity investments in, competitors of Kelt.
Conflicts, if any, will be subject to the procedures and remedies available under the ABCA. The ABCA provides that,
in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose
his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or
agreement unless otherwise provided by the ABCA. As at the date of this Annual Information Form, Kelt is not aware
of any existing or potential material conflicts of interest between Kelt and any director or officer of Kelt.
AUDIT COMMITTEE
Pursuant to NI 52-110, the Corporation is required to include in its Annual Information Form the disclosure required
under Form 52-110F1 – Audit Committee Information Required in an AIF with respect to its audit committee,
including the text of its audit committee charter, the composition of the audit committee and the fees paid to the
external auditor. This information is provided in Appendix D attached hereto.
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
Since the date of incorporation of Kelt, there have been no legal proceedings to which the Corporation is or was a
party to, or that any of the Corporation’s property is or was the subject of, which is or was, or can be reasonably
considered to be, material to the Corporation or any of its properties and the Corporation is not aware of any such
legal proceedings that are contemplated. For the purposes of the foregoing, a legal proceeding is not considered to be
“material” by the Corporation if it involves a claim for damages and the amount involved, exclusive of interest and
costs, does not exceed 10% of the Corporation’s current assets, provided that if any proceeding presents in large degree
the same legal and factual issues as other proceedings pending or known to be contemplated, the Corporation has
included the amount involved in the other proceedings in computing the percentage.
Since the date of incorporation of Kelt, there have been no penalties or sanctions imposed against the Corporation by
a court relating to securities legislation or by a securities regulatory authority, nor have there been any other penalties
or sanctions imposed by a court or regulatory body against the Corporation, and the Corporation has not entered into
any settlement agreements before a court relating to securities legislation or with a securities regulatory authority.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
None of the directors or executive officers of Kelt or any person or company that beneficially owns, or controls or
directs, directly or indirectly, more than 10% of the Common Shares, or any associate or affiliate of any of the
foregoing persons or companies, has or has had any material interest, direct or indirect, in any past transaction or any
proposed transaction that has materially affected or is reasonably expected to materially affect Kelt.
-56-
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Common Shares is Odyssey Trust Company. The Common Shares are
transferable at the offices of Odyssey Trust Company in Calgary, Alberta and Toronto, Ontario.
MATERIAL CONTRACTS
Except for contracts entered into in the ordinary course of business, there are no material contracts entered into by
Kelt since its incorporation and still in effect as at the date hereof that can be reasonably regarded as presently material.
INTERESTS OF EXPERTS
Sproule prepared the Sproule Report. The principals of Sproule own, directly or indirectly, less than 1% of the
outstanding Common Shares as at the date of this Annual Information Form. Sproule neither received nor will receive
any interest, direct or indirect, in any securities or other property of Kelt or its affiliates in connection with the
preparation of the Sproule Report.
PricewaterhouseCoopers LLP, Chartered Professional Accountants, are the auditors of Kelt and have confirmed that
they are independent with respect to Kelt in accordance with the Rules of Professional Conduct of the Chartered
Professional Accountants of Alberta. PricewaterhouseCoopers LLP, Chartered Professional Accountants, were
appointed the auditors of the Corporation on October 11, 2012.
ADDITIONAL INFORMATION
Additional information relating to the Corporation, including directors’ and officers’ remuneration and indebtedness,
principal holders of Common Shares and securities authorized for issuance under equity compensation plans, will be
contained in the Corporation’s Management Information Circular which relates to the Annual Meeting of Shareholders
to be held on April 20, 2022 and which will be filed on SEDAR under the Corporation’s profile at www.sedar.com.
Additional financial information is provided in the Corporation’s financial statements and management’s discussion
and analysis for the year ended December 31, 2021 filed under the Corporation’s profile at www.sedar.com.
-57-
APPENDIX A
Form 51-101F2
Report on Reserves Data
by Independent Qualified Reserves Evaluator or Auditor
To the Board of Directors of Kelt Exploration Ltd. (the “Company”):
1.
2.
3.
4.
5.
6.
7.
8.
We have evaluated the major properties and audited the minor properties of the Company’s reserves data as
at December 31, 2021. The reserves data are estimates of proved reserves and probable reserves and related
future net revenue as at December 31, 2021, estimated using forecast prices and costs.
The reserves data are the responsibility of the Company’s management. Our responsibility is to express an
opinion on the reserves data based on our evaluation or audit.
We carried out our evaluation of the major properties and audit of the minor properties in accordance with
standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”), as amended
and maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
Those standards require that we plan and perform an evaluation or audit to obtain reasonable assurance as to
whether the reserves data are free of material misstatement. An evaluation or audit also includes assessing
whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
The following table shows the net present value of future net revenue (before deduction of income taxes)
attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a
discount rate of 10 percent, included in the reserves data of the Company evaluated or audited for the year
ended December 31, 2021, and identifies the respective portions thereof that we have audited, evaluated and
reviewed and reported on to the Company’s management and Board of Directors:
Independent
Qualified
Reserves
Evaluator or
Auditor
Sproule
Total
Location
of
Reserves
(Country)
Effective Date
Net Present Value of Future Net Revenue
Before Income Taxes (10% Discount Rate)
Audited
(M$)
Evaluated
(M$)
Reviewed
(M$)
Total
(M$)
December 31, 2021
Canada
21,200
2,122,446
Nil
2,143,646
In our opinion, the reserves data evaluated or audited, by us have, respectively, in all material respects, been
determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion
on the reserves data that we reviewed but did not audit or evaluate.
We have no responsibility to update the report referred to in paragraph 5 for events and circumstances
occurring after the effective date of our report entitled “Evaluation of the P&NG Reserves of Kelt Exploration
Ltd. (As of December 31, 2021).”
Because the reserves data are based on judgements regarding future events, actual results will vary and the
variations may be material.
A-1
Executed as to our report referred to above:
Sproule Associates Limited
Calgary, Alberta
February 10, 2022
[(signed) “Steven J. Golko”]
Steven J. Golko, P.Eng.
Senior VP, Consulting Services
[(signed) “Alec Kovaltchouk”]
Alec Kovaltchouk, P. Geo.
VP, Geoscience
[(signed) “Cameron P. Six”]
Cameron P. Six, P. Eng.
Senior Petroleum Engineer
A-2
APPENDIX B
FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
Report of Management and Directors
on Reserves Data and Other Information
Management of Kelt Exploration Ltd. (the “Company”) are responsible for the preparation and disclosure of
information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements.
This information includes reserves data which are estimates of proved reserves and probable reserves and related
future net revenue as at December 31, 2021, estimated using forecast prices and costs.
An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent
qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.
The Reserves Committee of the board of directors of the Company has
(a)
(b)
reviewed the Company’s procedures for providing information to the independent qualified reserves
evaluator;
met with the independent qualified reserves evaluator to determine whether any restrictions affected
the ability of the independent qualified reserves evaluator to report without reservation; and
(c)
reviewed the reserves data with management and the independent qualified reserves evaluator.
The Reserves Committee of the board of directors has reviewed the Company’s procedures for assembling and
reporting other information associated with oil and gas activities and has reviewed that information with management.
The board of directors has, on the recommendation of the Reserves Committee, approved
(a)
(b)
the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves
data and other oil and gas information;
the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on
the reserves data; and
(c)
the content and filing of this report.
B-1
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations
may be material.
[(signed) “David J. Wilson]
David J. Wilson
President and Chief Executive Officer
[(signed) “Bruce Gigg]
Bruce Gigg
Vice President, Engineering
[(signed) “Michael R. Shea”]
Michael R. Shea
Director
[(signed) “Neil G. Sinclair]
Neil G. Sinclair
Director
Dated this 9th day of March, 2022.
B-2
APPENDIX C
DEFINITIONS USED FOR RESERVE CATEGORIES
The following definitions form the basis of the classification of reserves and values presented in the Sproule Report.
The definitions are those set out in NI 51-101 and/or the Canadian Oil and Gas Evaluation Handbook (the “COGE
Handbook”), as amended and maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and
incorporated into NI 51-101 by reference.
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable
from known accumulations, from a given date forward, based on:
analysis of drilling, geological, geophysical and engineering data;
the use of established technology;
specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed;
and
a remaining reserve life of 50 years.
Reserves are classified according to the degree of certainty associated with the estimates.
1.
Proved 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.
2.
Probable 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.
3.
Possible Reserves
Possible reserves are 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. Possible reserves have not been considered in the Sproule Report.
Other criteria that must also be met for categorization of reserves are provided in Section 5.5 of the COGE Handbook.
Each of the reserves categories (proved, probable, and possible) may be divided into developed or undeveloped
categories.
1.
Developed Reserves
Developed reserves are those reserves that are expected to be recovered from existing wells and installed
facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared
to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided
into producing and non-producing.
2.
Developed Producing Reserves
Developed producing reserves are those reserves that are expected to be recovered from completion intervals
open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have
previously been on production, and the date of resumption of production must be known with reasonable
certainty.
C-1
3.
Developed Non-Producing Reserves
Developed non-producing reserves are those reserves that either have not been on production, or have
previously been on production, but are shut in, and the date of resumption of production is unknown.
4.
Undeveloped Reserves
Undeveloped reserves are those reserves expected to be recovered from known accumulations where a
significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable
of production. They must fully meet the requirements of the reserves classification (proved, probable,
possible) to which they are assigned.
In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and
undeveloped categories or to subdivide the developed reserves for the pool between developed producing
and developed non-producing. This allocation should be based on the estimator’s assessment as to the
reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their
respective development and production status.
5.
Levels of Certainty for Reported Reserves
The qualitative certainty levels contained in the definitions in Sections 1, 2 and 3 are applicable to individual
reserves entities, which refers to the lowest level at which reserves estimates are made, and to reported
reserves, which refers to the highest level sum of individual entity estimates for which reserve estimates are
made.
Reported total reserves estimated by deterministic or probabilistic methods, whether comprised of a single
reserves entity or an aggregate estimate for multiple entities, should target the following levels of certainty
under a specific set of economic conditions:
(a)
(b)
(c)
There is a 90% probability that at least the estimated proved reserves will be recovered.
There is a 50% probability that at least the sum of the estimated proved reserves plus probable
reserves will be recovered.
There is a 10% probability that at least the sum of the estimated proved reserves plus probable
reserves plus possible reserves will be recovered.
A quantitative measure of the probability associated with a reserves estimate is generated only when a
probabilistic estimate is conducted. The majority of reserves estimates will be performed using deterministic
methods that do not provide a quantitative measure of probability. In principle, there should be no difference
between estimates prepared using probabilistic or deterministic methods.
Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is
provided in Section 5.5.3 of the COGE Handbook. Whether deterministic or probabilistic methods are used,
evaluators are expressing their professional judgement as to what are reasonable estimates.
C-2
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
Remaining Recoverable Reserves are the total remaining recoverable reserves associated with the acreage
in which the Corporation has an interest.
Company Gross Reserves are the Corporation’s working interest share of the remaining reserves, before
deduction of any royalties.
Company Net Reserves are the gross remaining reserves of the properties in which the Corporation has an
interest, less all Crown, freehold, and overriding royalties and interests owned by others.
Net Production Revenue is income derived from the sale of net reserves of oil, pipeline gas, and gas
by-products, less all capital and operating costs.
Fair Market Value is defined as the price at which a purchaser seeking an economic and commercial
return on investment would be willing to buy, and a vendor would be willing to sell, where neither is under
compulsion to buy or sell and both are competent and have reasonable knowledge of the facts.
Barrels of Oil Equivalent (BOE) Reserves - BOE is the sum of the oil reserves, plus the gas reserves
divided by a factor of 6, plus the natural gas liquid reserves, all expressed in barrels or thousands of barrels.
Equivalent reserves can also be expressed in thousands of cubic feet of gas equivalent (McfGE) using a
conversion ratio of 1 bbl:6 Mcf.
Oil (or Crude Oil) – a mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the
liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may
contain small amounts of sulphur and other non-hydrocarbons, but does not include liquids obtained from
the processing of natural gas. Crude oil volumes are further divided into Product Types, for reporting
purposes.
Gas (or Natural Gas) – a mixture of lighter hydrocarbons that exist either in the gaseous phase or in
solution in crude oil in reservoirs, but are gaseous at atmospheric conditions. Natural gas may contain
sulphur or other non-hydrocarbon compounds. Natural gas volumes are further divided into Product Types,
for reporting purposes.
Non-Associated Gas – an accumulation of natural gas in a reservoir where there is no crude oil.
Associated Gas - the gas cap overlying a crude oil accumulation in a reservoir.
Solution Gas - gas dissolved in crude oil.
Natural Gas By Products – those components that can be removed from natural gas including, but not
limited to, ethane, propane, butanes, pentanes plus, condensate, and small quantities of non-hydrocarbons.
Products Types – sub-classify the principle product types of petroleum, crude oil, gas and by-products,
into specific groupings based on the properties of the hydrocarbon and the properties of the accumulation
and reservoir rock from which it is found. Regulatory agencies may define in legislation the production
types they require to be used for reporting purposes in their jurisdiction. The Canadian Securities
Association (CSA) defines the following Product Types for reporting purposes in National Instrument
51-101, effective July 1, 2015.
Crude Oil
(a)
(b)
Light Crude Oil means crude oil with a relative density greater than 31.1 degrees API gravity;
Medium Crude Oil means crude oil with a relative density greater than 22.3 degrees API gravity
and less than or equal to 31.1 degrees API gravity;
C-3
(c)
Heavy Crude Oil means crude oil with a relative density greater than 10 degrees API gravity and
less than or equal to 22.3 degrees API gravity;
(d)
Tight Oil means crude oil:
(i)
contained in dense organic rich rocks, including low-permeability shales, siltstones and
carbonates, in which the crude oil is primarily contained in microscopic pore spaces that
are poorly connected to one another, and
(ii)
that typically requires the use of hydraulic fracturing to achieve economic production rates;
(e)
Bitumen means a naturally occurring solid or semi-solid hydrocarbon:
(i)
(ii)
consisting mainly of heavier hydrocarbons, with a viscosity greater than 10,000
millipascal-seconds (mPa.s) or 10,000 centipoise (cP) measured at the hydrocarbon’s
original temperature in the reservoir and at atmospheric pressure on a gas-free basis, and
that is not primarily recoverable at economic rates through a well without the
implementation of enhanced recovery methods;
(f)
Synthetic Crude Oil means a mixture of liquid hydrocarbons derived by upgrading bitumen,
kerogen or other substances such as coal, or derived from gas to liquid conversion and may contain
sulphur or other compounds;
Natural Gas
(g)
Conventional Natural Gas means natural gas that has been generated elsewhere and has migrated
as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be
formed by localized structural, depositional or erosional geological features;
(h)
CoalBed Methane means natural gas that:
(i)
primarily consists of methane, and
(ii)
is contained in a coal deposit;
(i)
Shale Gas means natural gas:
(i)
contained in dense organic-rich rocks, including low-permeability shales, siltstones and
carbonates, in which the natural gas is primarily absorbed on the kerogen or clay minerals,
and
(ii)
that usually requires the use of hydraulic fracturing to achieve economic production rates;
(j)
Synthetic Gas means a gaseous fluid:
(i)
generated as a result of the application of an in-situ transformation process to coal or other
hydrocarbon-bearing rock, and
(ii)
comprised of not less than 10% by volume of methane;
(k)
Gas Hydrate means a naturally occurring crystalline substance composed of water and gas in an
ice-lattice structure;
C-4
By-Products
(l)
Natural Gas Liquids means those hydrocarbon components that can be recovered from natural gas
as a liquid including, but not, limited to, ethane, propane, butanes, pentanes plus and condensates;
and
(m)
Sulphur is a non-hydrocarbon elemental by-product of gas processing and refining.
C-5
APPENDIX D
FORM 52-110F1 – AUDIT COMMITTEE INFORMATION REQUIRED IN AN AIF
1.
The Audit Committee Charter
The charter of the Audit Committee is attached as Schedule 1 to this Appendix D.
2.
Composition of the Audit Committee
The Audit Committee of the Corporation is composed of the following individuals:
Member
Independent
Financially literate
Geraldine L. Greenall
Independent(1)
Financially literate(2)
Neil Sinclair
Janet Vellutini
Independent(1)
Financially literate(2)
Independent(1)
Financially literate(2)
Notes:
(1)
(2)
A member of an audit committee is independent if the member has no direct or indirect material relationship with the Corporation which
could, in the view of the Board of Directors, reasonably interfere with the exercise of a member’s independent judgment.
An individual is financially literate if he has the ability to read and understand a set of financial statements that present a breadth and
level of complexity of accounting issues that are generally comparable to the breadth and level of complexity of accounting issues that
can reasonably be expected to be raised by the Corporation’s financial statements.
3.
Relevant Education and Experience
Ms. Greenall holds a Bachelor of Commerce (Finance), a CFA and an ICD.D, having completed the Institute of
Corporate Directors – Directors Education Program and has over 3 years of public issuer experience as a director. Ms.
Greenall is also the Chief Financial Officer of a publicly listed exploration and production corporation.
Mr. Sinclair, the Chair of the Audit Committee, holds a BA and an MBA. He has also been President of an active
private corporation, with significant real estate operations, for over 48 years. He also has over 19 years of public
company experience as an officer and as a director.
Ms. Vellutini is a professional engineer and has extensive experience in gas marketing and most recently was a
Marketing Consultant at a Calgary-based private energy company. She has over 30 years of experience in gas
marketing and a total of 36 years in the oil and gas industry. [NTD: Expand on any other relevant education or
experience]
4.
Reliance on Certain Exemptions
At no time since incorporation has the Corporation relied on any exemption from NI 52-110, other than in Section 2.4
of NI 52-110 (De Minimis Non-audit Services).
5.
Reliance on the Exemption in Subsection 3.3(2) or Section 3.6
At no time since incorporation has the Corporation relied on the exemptions in Sections 3.3(2) or 3.6 of NI 52-110.
6.
Reliance on Section 3.8
At no time since incorporation has the Corporation relied on Section 3.8 of NI 52-110.
7.
Audit Committee Oversight
At no time since incorporation was a recommendation of the Audit Committee to nominate or compensate an external
auditor not adopted by the Board of Directors.
D-1
8.
Pre-Approval Policies and Procedures
The Audit Committee of the Corporation has adopted specific policies and procedures for the engagement of non-
audit services entitled “Procedures for Approval of Audit and Non-Audit Services by the External Auditors”
(the “Procedure”). Under the Procedure, the auditors may not act in any capacity where they function as management,
audit their own work or serve in an advocacy role on behalf of the Corporation. Various audit related services provided
by the auditors have been pre-approved. Management is required, however, to obtain pre-approval of the Audit
Committee for services where engagement fees are expected to exceed $20,000. Where fees for a particular
engagement are expected to be less than or equal to $20,000 the Chair of the Audit Committee is to be notified
expeditiously of the commencement of such services. If an engagement with the auditors for a particular service is
contemplated that is neither expressly forbidden under the Procedure nor covered under the range of services provided
for therein, such an engagement must be pre-approved. The Audit Committee has delegated the authority to effect
such pre-approval to the Chair of the Audit Committee. Pre-approved non-audit services shall be provided pursuant
to an engagement letter signed by the auditors which shall set out the particular non-audit services to be provided. At
every regularly scheduled meeting of the Audit Committee, management is required to report on all new pre-approved
engagements of the auditors since the last such report.
9.
External Auditor Service Fees (By Category)
The aggregate fees billed by the Corporation’s external auditors in each of the last two fiscal years are set forth in the
table below:
Year Ended
December 31, 2021
December 31, 2020
Audit Fees (1)
$201,800
$173,700
Audit-Related Fees(2)
$45,000
$38,000
Tax Fees(3)
All Other Fees(4)
$24,000
$24,000
nil
$92,700
Notes:
(1)
(2)
(3)
(4)
The aggregate audit fees paid or payable.
Audit related services include quarterly reviews, procedures related to new accounting standards and complex transaction
accounting.
The aggregate fees billed for professional services rendered for tax advice and tax planning
The aggregate non-re-occurring fees billed for professional services primarily rendered for commodity tax recovery
engagement.
D-2
SCHEDULE 1
AUDIT COMMITTEE CHARTER OF KELT EXPLORATION LTD.
This charter governs the operations of the audit committee (the “Committee”) of Kelt Exploration Ltd.
(the “Corporation”). The Committee shall report to the Board of Directors (the “Board”) of the Corporation. The
following is the text of the Committee’s charter.
I.
PURPOSE
(a)
The primary function of the Committee is to assist the Board in fulfilling its responsibilities
regarding the integrity of the Corporation’s financial statements including the financial reporting
process and systems of internal controls, the compliance by the Corporation with legal and
regulatory requirements and the qualifications, performance and independence of the Corporation’s
external auditor by reviewing:
(i)
the financial information that will be provided to the shareholders, regulatory authorities
and others;
(ii)
the systems of internal controls management has established;
(iii)
all audit processes;
(iv)
all reporting from the external auditors.
(b)
Primary responsibility for the financial reporting, information systems, risk management and
internal controls of the Corporation is vested in management and is overseen by the Board. While
the Committee has the responsibilities and powers set forth in this Charter, it is not the duty of the
Committee to plan or conduct audits or to determine that the Corporation’s financial statements are
complete and accurate and are in accordance with generally accepted accounting principles. These
are the responsibilities of management and the external auditor. Nor is it the duty of the Committee
to conduct investigations, to resolve disagreements, if any, between management and the external
auditor or to assure compliance with laws and regulations.
II.
COMPOSITION AND OPERATIONS
(a)
(b)
(c)
(d)
The Committee shall be composed of not fewer than three directors, none of whom shall be officers,
employees or consultants to the Corporation or any of its related legal entities. The Committee shall
only be comprised of unrelated directors. An unrelated director is a director who is independent of
management and is free from any interest or other relationship which could reasonably be perceived
to materially interfere with the director’s ability to act with a view to the best interests of the
Corporation as the case may be, other than interests and relationships arising from shareholding.
The Committee shall review and reassess this Charter annually.
All Committee members shall be financially literate (as defined by the Toronto Stock Exchange or
other regulatory authority), or shall become financially literate within a reasonable period of time
after appointment to the Committee, and at least one member shall have appropriate financial
management experience or expertise.
The Corporation’s auditors shall be advised of the names of the Committee members and when
appropriate will receive notice of and be invited to attend meetings of the Committee and to be heard
at those meetings on matters relating to the auditor’s duties.
S-1
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
The Committee shall meet with the external auditors as it deems appropriate to consider any matter
that the Committee or auditors determine should be brought to the attention of the Board or
shareholders.
The Committee shall meet at least four times each year.
The Committee shall have access to the Corporation’s senior management and documents as
required to fulfill its responsibilities and is provided with the resources necessary to carry out its
responsibilities.
The Committee shall provide open avenues of communication among management, employees,
external auditors and the Board.
The secretary to the Committee shall be the Corporate Secretary or an appointee of the Corporate
Secretary.
Notice of the time and place of every meeting shall be given to each Committee member at least 48
hours prior to the meeting.
A majority of the voting membership of the Committee present in person or by telephone or other
electronic telecommunication device shall constitute a quorum.
The President, Chief Executive Officer, Vice President, Finance, and Chief Financial Officer and
external auditor would be expected to be available to attend meetings or portions thereof. The
external auditors would meet at least twice annually with the Committee. Others may or may not
attend the meetings at the sole discretion of the Committee.
(m)
Minutes of Committee meetings shall be approved by the Committee and sent to all directors of the
Board.
III.
DUTIES AND RESPONSIBILITIES
(a)
Financial Statements and Other Financial Information
The Committee will review and recommend for approval to the Board financial information that
will be made publicly available. This includes:
(i)
(ii)
the Corporation’s annual and quarterly financial statements;
the Corporation’s press releases and reports as they relate to the finances of the
Corporation;
(iii)
the Management Discussion and Analysis;
(iv)
the financial content of the Annual Report;
(v)
(vi)
the Annual Information Form and any Prospectus or Private Placement Memorandums;
and
any reports required by regulatory or government authorities as they relate to the finances
of the Corporation.
S-2
The Committee will review and discuss:
(vii)
the appropriateness of accounting policies and financial reporting practices to be adopted
by the Corporation;
(viii)
any significant proposed changes in financial reporting and accounting policies and
practices to be adopted by the Corporation;
(ix)
any new or pending developments in accounting and reporting standards that may affect
the Corporation;
(x)
ascertain compliance with the covenants under applicable loan agreements;
(xi)
(xii)
management’s key estimates and judgments that may be material to financial reporting;
and
any other matters required to be reviewed under applicable legal, regulatory or stock
exchange requirements.
(b)
Risk Management, Internal Control and Information Systems
The Committee will review and obtain reasonable assurance that the risk management, internal
control and information systems are operating effectively to produce accurate, appropriate and
timely management and financial information. This includes:
(i)
(ii)
review the Corporation’s risk management controls and policies;
obtain reasonable assurance that the information systems are reliable and the systems of
internal controls are properly designed and effectively implemented through discussions
with and reports from management and the external auditor;
(iii)
review management steps to implement and maintain appropriate internal control
procedures including a review of policies;
(iv)
review adequacy of security of information, information systems and recovery plans;
(v)
monitor compliance with statutory and regulatory obligations;
(vi)
review the appointment of the Vice President, Finance and Chief Financial Officer; and
(vii)
review the adequacy of accounting and finance resources.
(c)
External Audit
The Committee will review the planning and results of external audit activities and the ongoing
relationship with the external auditor. This includes:
(i)
(ii)
review and recommend to the Board, for shareholder approval, engagement of the external
auditor including, as part of such review and recommendation, an evaluation of the external
auditors qualifications, independence and performance;
review and recommend to the Board the annual external audit plan, including but not
limited to the following:
1.
engagement letter;
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2.
3.
4.
5.
6.
7.
8.
objectives and scope of the external audit work;
procedures for quarterly review of financial statements;
materiality limit;
areas of audit risk;
staffing;
timetable; and
proposed fees.
(iii)
meet with the external auditor to discuss the Corporation’s quarterly and annual financial
statements and the auditor’s report including the appropriateness of accounting policies
and underlying estimates;
(iv)
review and advise the Board with respect to the planning, conduct and reporting of the
annual audit, including but not limited to:
1.
2.
3.
4.
5.
any difficulties encountered, or restrictions imposed by management during the
annual audit;
any significant accounting or financial reporting issue including the resolution of
any disagreement between management and the external auditors;
the auditor’s evaluation of the Corporation’s system of internal controls,
procedures and documentation;
the post audit or management letter containing any findings or recommendation
of the external auditor, including management’s response thereto and the
subsequent follow-up to any identified internal control weakness; and
assess the performance and consider the annual appointment of external auditors
for recommendation to the Board;
(v)
review and receive assurances on the independence of the external auditor;
(vi)
review the non-audit services to be provided by the external auditor’s firm and consider
the impact on the independence of the external audit; and
(vii)
meet periodically with the external auditor without management present.
(d)
Other
(i)
(ii)
review material litigation and its impact on financial reporting; and
establish procedures for the receipt, retention and treatment of complaints received by the
Corporation regarding accounting, internal controls or auditing matters and the
confidential, anonymous submission by employees of concerns regarding questionable
accounting or auditing matters.
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IV.
ACCOUNTABILITY
The committee shall report its discussions to the Board by distributing the minutes of its meetings and where
appropriate, by oral report at the next Board meeting.
V.
STANDARDS OF LIABILITY
Nothing contained in this Charter is intended to expand applicable standards of liability under statutory, regulatory or
other legal requirements for the Board or members of the Committee. The purposes and responsibilities outlined in
these terms of reference are meant to serve as guidelines rather than inflexible rules and the Committee may adopt
such additional procedures and standards as it deems necessary to fulfill its responsibilities.
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