________
Annual Information Form
For the Year Ended December 31, 2017
Dated March 14, 2018
Table of Contents
Select Definitions .......................................................................................................................................... 3
Abbreviations and Conversion ...................................................................................................................... 4
Non-IFRS Measures ..................................................................................................................................... 5
Notes on Reserves Data and Other Oil and Natural Gas Information .......................................................... 5
Special Note Regarding Forward Looking Statements ................................................................................. 7
Surge Energy Inc. ....................................................................................................................................... 10
Development of the Business ..................................................................................................................... 10
Description of the Business......................................................................................................................... 11
Principal Producing Properties .................................................................................................................... 14
Statement of Reserves Data ....................................................................................................................... 16
Description of Capital Structure .................................................................................................................. 25
Dividend Policy ............................................................................................................................................ 26
Market for Securities ................................................................................................................................... 27
Directors and Officers ................................................................................................................................. 28
Audit Committee .......................................................................................................................................... 31
Industry Conditions ..................................................................................................................................... 33
Risk Factors ................................................................................................................................................ 50
Legal Proceedings And Regulatory Actions ................................................................................................ 61
Interest of Management and Others in Material Transactions .................................................................... 61
Auditor, Transfer Agent and Registrar ........................................................................................................ 61
Interest of Experts ....................................................................................................................................... 61
Additional Information ................................................................................................................................. 62
Schedule “A” – Form 51-101F2
Schedule “B” – Form 51-101F3
Schedule “C” – Audit Committee Charter
SELECT DEFINITIONS
Unless the context indicates otherwise, the following terms shall have the meanings set out below when
used in this Annual Information Form. Certain other terms and abbreviations used herein, but not defined
herein, are defined in NI 51-101 or the COGE Handbook and, unless the context otherwise requires, shall
have the same meanings herein as in NI 51-101 or the COGE Handbook.
“ABCA” means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended;
“AIF” or “Annual Information Form” means this annual information form;
“Audit Committee” means the audit committee of the Board;
“Board of Directors” or “Board” means the board of directors of the Corporation;
“COGE Handbook” means the “Canadian Oil and Gas Evaluation Handbook” maintained by the Society
of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time;
“Common Shares” means the common shares of the Corporation;
“Corporation” or “Surge” means Surge Energy Inc., a corporation amalgamated under the ABCA;
“Credit Facility” means the $305 million extendible revolving term credit facility of the Corporation with a
banking syndicate led by National Bank of Canada, as amended from time to time;
“Debentures” means the 5.75% convertible unsecured subordinated debentures due on December 31,
2022, as more particularly described under the heading “Description of Capital Structure”;
“Indenture” means the debenture indenture between Surge and Computershare Trust Company of
Canada under which the Debentures are issued;
“NI 51-101” means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities;
“Reserves Report” means the independent engineering report dated February 9, 2018 and effective
December 31, 2017 prepared by and containing the evaluation of Sproule of the oil, NGL and natural gas
reserves attributable to the properties of the Corporation;
“Sproule” means Sproule Associates Limited, independent oil and gas reservoir engineers; and
“TSX” means the Toronto Stock Exchange.
Words importing the singular number only include the plural, and vice versa, and words importing any
gender include all genders. All dollar amounts set forth in this Annual Information Form, including “dollar”,
“$” and “CAD$” are in Canadian dollars, except where otherwise indicated. “US$” means United States
dollars.
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In this Annual Information Form, the abbreviations set forth below have the following meanings:
ABBREVIATIONS AND CONVERSION
Oil and Natural Gas Liquids
Natural Gas
bbl
bbls
Mbbls
MMbbls
Mstb
bbl/d
NGLs
stb
Barrel
Barrels
thousand barrels
million barrels
1,000 stock tank barrels
barrels per day
natural gas liquids
stock tank barrel
Mcf
MMcf
Mcf/d
MMcf/d
MMbtu
Bcf
GJ
thousand cubic feet
million cubic feet
thousand cubic feet per day
million cubic feet per day
million British Thermal Units
billion cubic feet
gigajoule
The following table sets forth certain standard conversions from Standard Imperial Units to the
International System of Units (or metric units).
To Convert From
To
Multiply By
Mcf
Cubic metres
Bbls
Cubic metres
Feet
Metres
Miles
Kilometres
Acres
Hectares
Gigajoules
MMbtu
Cubic metres
Cubic feet
Cubic metres
Bbls
Metres
Feet
Kilometres
Miles
Hectares
Acres
MMbtu
Gigajoules
28.174
35.494
0.159
6.293
0.305
3.281
1.609
0.621
0.405
2.50
0.950
1.0526
Other
AECO
API
°API
boe
boe/d
m3
Mboe
MMboe
$000s
M$ or $M
MM$
WTI
a natural gas storage facility located at Suffield, Alberta
American Petroleum Institute
an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid
petroleum with a specified gravity of 35.1° API or greater is generally referred to as light
crude oil. Liquid petroleum with a specified gravity of 25.8° to 35° API or greater is
generally referred to as medium crude oil. Liquid petroleum with a specified gravity of
25.7° API or lower is generally referred to as heavy crude oil.
barrel of oil equivalent on the basis of 1 boe to 6 Mcf of natural gas. Boes may be
misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6 Mcf is
based on an energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead
barrel of oil equivalent per day
cubic metres
1,000 barrels of oil equivalent
1,000,000 barrels of oil equivalent
thousands of dollars
thousands of dollars
millions of dollars
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma
for crude oil of standard grade
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NON-IFRS MEASURES
This AIF contains the term “netback” which is not defined by IFRS and therefore may not be comparable
to performance measures presented by others. In this AIF, “netback” is calculated by deducting royalties
paid and production costs, including transportation costs, from prices received, excluding the effects of
hedging. Management believes that in addition to net income, netbacks are a useful supplemental
measure as it assists in the determination of the Corporation’s operating performance. Readers should
be cautioned, however, that this measure should not be construed as an alternative to both net income
and net cash from (used in) operating activities, which are determined in accordance with IFRS, as
indicators of the Corporation’s performance.
NOTES ON RESERVES DATA AND OTHER OIL AND NATURAL GAS INFORMATION
Caution Respecting Reserves Information
The determination of oil and natural gas reserves involves the preparation of estimates that have an
inherent degree of associated uncertainty. Categories of proved and probable reserves have been
established to reflect the level of these uncertainties and to provide an indication of the probability of
recovery. The estimation and classification of reserves requires the application of professional judgment
combined with geological and engineering knowledge to assess whether or not specific reserves
classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk,
probability and statistics, and deterministic and probabilistic estimation methods is required to properly
use and apply reserves definitions. The estimates of reserves and future net revenue for individual
properties may not reflect the same confidence level as estimates of reserves and future net revenue for
all properties, due to the effects of aggregation.
The recovery and reserve estimates of oil, NGL and natural gas reserves provided herein are
estimates only. Actual reserves may be greater than or less than the estimates provided herein.
The estimated future net revenue from the production of the Corporation’s natural gas and
petroleum reserves does not represent the fair market value of the Corporation’s reserves.
Caution Respecting Boe
In this AIF, the abbreviation boe means 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.
Definitions
Certain terms used in this AIF in describing reserves and other oil and natural gas information are defined
below. Certain other terms and abbreviations used in this AIF, but not defined or described, are defined in
NI 51-101 or the COGE Handbook and, unless the context otherwise requires, shall have the same
meanings herein as in NI 51-101 or the COGE Handbook.
Reserves
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: (i) analysis of drilling,
geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified
economic conditions, which are generally accepted as being reasonable and shall be disclosed.
Reserves are classified according to the degree of certainty associated with the estimates as follows:
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“proved reserves” are those reserves that can be estimated with a high degree of certainty to be
recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved
reserves.
“probable reserves” are those additional reserves that are less certain to be recovered than proved
reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the
sum of the estimated proved plus probable reserves.
The qualitative certainty levels referred to in the definitions above are applicable to “individual reserves
entities” (which refers to the lowest level at which reserves calculations are performed) and to “reported
reserves” (which refers to the highest-level sum of individual entity estimates for which reserves estimates
are presented). Reported reserves should target the following levels of certainty under a specific set of
economic conditions:
• at least a 90 percent probability that the quantities actually recovered will equal or exceed the
estimated proved reserves; and
• at least a 50 percent probability that the quantities actually recovered will equal or exceed the
sum of the estimated proved plus probable reserves.
Each of the reserves categories (proved and probable) may be divided into developed and undeveloped
categories as follows:
“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 as follows:
“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.
“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.
“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 sub-divide 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.
Interests in Reserves, Production, Wells and Properties
“gross” means: (i) in relation to an issuer’s interest in production or reserves, its “company gross
reserves”, which are its working interest (operating or non-operating) share before deduction of royalties
and without including any royalty interests of the issuer; (ii) in relation to wells, the total number of wells in
which an issuer has an interest; and (iii) in relation to properties, the total area of properties in which an
issuer has an interest.
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“net” means: (i) in relation to an issuer’s interest in production or reserves its working interest (operating
or non-operating) share after deduction of royalty obligations, plus its royalty interests in production or
reserves; (ii) in relation to an issuer’s interest in wells, the number of wells obtained by aggregating the
issuer’s working interest in each of its gross wells; and (iii) in relation to an issuer’s interest in a property,
the total area in which the issuer has an interest multiplied by the working interest owned by the issuer.
“working interest” means the percentage of undivided interest held by an issuer in the oil and/or natural
gas or mineral lease granted by the mineral owner, Crown or freehold, which interest gives the issuer the
right to “work” the property (lease) to explore for, develop, produce and market the leased substances.
Description of Exploration and Development Wells and Costs
“development costs” means costs incurred to obtain access to reserves and to provide facilities for
extracting, treating, gathering and storing the crude oil and natural gas from the reserves. More
specifically, development costs, including applicable operating costs of support equipment and facilities
and other costs of development activities, are costs incurred to: (i) gain access to and prepare well
locations for drilling, including surveying well locations for the purpose of determining specific
development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines
and power lines, to the extent necessary in developing the reserves; (ii) drill, complete and equip
development wells, development type stratigraphic test wells and service wells, including the costs of
platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly; (iii)
acquire, construct and install production facilities such as flow lines, separators, treaters, heaters,
manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants,
and central utility and waste disposal systems; and (iv) provide improved recovery systems.
“development well” means a well drilled inside the established limits of an oil or gas reservoir, or in close
proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.
“exploration costs” means costs incurred in identifying areas that may warrant examination and in
examining specific areas that are considered to have prospects that may contain oil and natural gas
reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells.
Exploration costs may be incurred both before acquiring the related property (sometimes referred to in
part as “prospecting costs”) and after acquiring the property. Exploration costs, which include applicable
operating costs of support equipment and facilities and other costs of exploration activities, are: (i) costs
of topographical, geochemical, geological and geophysical studies, rights of access to properties to
conduct those studies, and salaries and other expenses of geologists, geophysical crews and others
conducting those studies (collectively sometimes referred to as “geological and geophysical costs”); (ii)
costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and
capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
(iii) dry hole contributions and bottom hole contributions; (iv) costs of drilling, completing and equipping
exploratory wells; and (v) costs of drilling exploratory type stratigraphic test wells.
“exploration well” means a well that is not a development well, a service well or a stratigraphic test well.
“service well” means a well drilled or completed for the purpose of supporting production in an existing
field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane,
butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for
injection, observation or injection for combustion.
SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS
Certain statements or disclosures contained in this Annual Information Form constitute forward-looking
statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”,
“project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements.
These statements involve known and unknown risks, uncertainties and other factors that may cause
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actual results or events to differ materially from those anticipated in such forward-looking statements.
The Corporation believes the expectations reflected in those forward-looking statements are reasonable,
but no assurance can be given that these expectations will prove to be correct. Since forward-looking
statements address future events and conditions, by their very nature they involve inherent risks and
uncertainties. Such forward-looking statements included in this Annual Information Form should not be
unduly relied upon. These statements speak only as of the date of this Annual Information Form.
In particular, this Annual Information Form may contain forward-looking statements and information
pertaining to the following:
the performance characteristics of the Corporation’s oil and natural gas properties;
•
• oil and natural gas production levels, and expectations of future production rates, volumes and
•
product mixes;
the size of the oil and natural gas reserves of the Corporation and anticipated future cash flows from
such reserves;
• projections of market prices and costs, and exchange and inflation rates;
• supply and demand for oil and natural gas;
• expectations regarding the ability to raise capital and to continually add to reserves through
acquisitions and development;
the Corporation’s dividend policy and the amount of timing of dividends;
treatment under governmental regulatory regimes and tax and royalty laws;
•
•
• criteria and considerations in participations and acquisitions;
•
•
• estimated abandonment and reclamation costs and the timing thereof;
• expected land expiries and plans with respect thereto;
• plans to implement enhanced recovery; and
• capital expenditure programs, the allocation of such capital and the timing thereof.
tax horizon;
timing of development of undeveloped reserves;
With respect to forward looking statements contained in this Annual Information Form, the Corporation
has made assumptions regarding:
the success of the Corporation’s operations and exploration and development activities;
the size of Surge’s oil, natural gas and NGL reserves and the recoverability of its reserves;
the availability of labour, services and drilling equipment;
the availability of capital to fund planned expenditures;
timing and amount of capital expenditures;
future operating costs and future cash flow;
the Corporation’s future debt levels;
• oil and natural gas production levels and the timing of new wells coming on-stream;
•
•
• prevailing weather conditions, commodity prices and exchange rates;
•
•
•
•
•
• general economic and financial market conditions;
•
•
•
•
• government regulation in the areas of taxation, royalty rates and environmental protection.
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 success, nature and timing of water flood activities;
the ability of the Corporation to secure necessary capital, personnel, equipment and services; and
The actual results, performance or achievements of the Corporation may differ materially from those
anticipated in these forward-looking statements as a result of the risk factors set forth below and
elsewhere in this Annual Information Form:
• volatility in market prices for oil and natural gas;
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liabilities inherent in oil and natural gas operations;
• volatility in exchange rates;
•
• uncertainties associated with estimating oil and natural gas reserves and production levels;
•
inability to secure labour, services or equipment on a timely basis or on favourable terms;
•
failure to obtain industry partner or other third party consents and approvals, when required;
• competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled
personnel;
fluctuations in the cost of borrowing;
the inability to access sufficient capital from internal and external sources;
•
•
• changes in general economic, market and business conditions;
• unanticipated operating events which can reduce production or cause production to be shut in or
delayed;
• unfavourable weather conditions;
•
incorrect assessments of the value of acquisitions, dispositions and exploration and development
programs;
• geological, technical, drilling, completion and processing problems;
• results of water flood responses;
•
the outcome of litigation or regulatory proceedings brought against the Corporation or other disputes
involving the Corporation;
• changes in legislation, including changes in tax laws and incentive programs relating to the oil and
gas industry;
• cyber-security issues;
•
•
failure to realize the anticipated benefits of acquisitions and dispositions; and
the other factors discussed under “Risk Factors”.
Statements relating to “reserves” or “resources” are deemed to be 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.
Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking
statements contained in this Annual Information Form are expressly qualified by this cautionary
statement. The Corporation does not undertake any obligation to publicly update or revise any
forward-looking statements other than as required under applicable securities laws.
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Corporate Structure
SURGE ENERGY INC.
Surge was incorporated on January 26, 1998 under the ABCA as “Zapata Capital Inc.” On June 18,
1999, the Corporation acquired all of the issued and outstanding shares of 744997 Alberta Ltd. and
amalgamated with 744997 Alberta Ltd. under the name “Zapata Energy Corporation”. On June 25, 2010,
the Corporation changed its name to “Surge Energy Inc.” On December 31, 2010, the Corporation
amalgamated with its wholly owned subsidiary, Breaker Resources Ltd. On December 31, 2012, the
Corporation amalgamated with is wholly owned subsidiary, Surge Oil Inc. On December 31, 2013, the
Corporation amalgamated with its wholly owned subsidiaries, Flagstone Energy Inc. and 1779275 Alberta
Ltd. On December 31, 2014, the Corporation amalgamated with its wholly owned subsidiary, Longview
Oil Corp.
The head office of the Corporation is located at 2100, 635 – 8th Avenue S.W., Calgary, Alberta T2P 3M3.
The registered office of the Corporation is located at Suite 4000, 421 – 7th Avenue S.W., Calgary, Alberta,
T2P 4K9.
Intercorporate Relationships
The Corporation currently has one wholly-owned subsidiary, 1413942 Alberta Ltd. The Corporation and
1413942 Alberta Ltd. are the partners of Surge General Partnership. The corporate structure of the
Corporation and its subsidiaries is as set forth in the diagram below:
General
DEVELOPMENT OF THE BUSINESS
The Corporation is an independent Calgary, Alberta-based oil and gas company operating primarily in
Alberta and Saskatchewan. The Common Shares are listed on the TSX under the symbol “SGY” and the
Debentures are listed on the TSX under the symbol “SGY.DB”.
Three Year History
Significant developments of the Corporation over the last three completed financial years are as set forth
below:
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Year ended December 31, 2015
SE Saskatchewan and Manitoba Disposition
On June 15, 2015, the Corporation completed the disposition of certain oil and gas assets in SE
Saskatchewan for cash consideration of $430 million. The sold assets comprised of approximately 4,750
boe/d of production at the time of disposition and approximately 23 million boe of proved plus probable
reserves. The assets also included an average working interest of approximately 76 percent in 142,945
gross (109,321 net) acres of undeveloped land including Fee acreage as at the time of disposition, 2015,
with an internally estimated value of $137 million. Production from the assets was weighted 95 percent to
light crude oil (30° API). The properties involved were Macoun, Pinto and Alida in Saskatchewan and
Manson in Manitoba.
Year ended December 31, 2016
Asset Sales
On March 24, 2016, Surge completed the sale of certain facilities at its Valhalla light oil and natural gas
assets in NW Alberta for $15 million. The Corporation will maintain control of the Valhalla facilities as
operator, and will pay the purchaser an annual tariff for the life of the agreement. Surge will also retain all
third-party processing revenues generated from the facilities. On March 31, 2016 Surge also closed the
previously announced sale of the Corporation’s non-core Sunset property in Northern Alberta for
proceeds of $28 million. The $43 million in combined sale proceeds have been used to pay down the
Corporation’s existing credit facility.
Asset Acquisition
In the fourth quarter of 2016, Surge purchased Montney reserves and production associated with 3
sections of 100 percent working interest lands within the Valhalla Montney B Oil pool. The purchase also
included a 1.97 percent working interest ownership in a nearby sour gas processing facility. The portion
of the pool purchased contains over 27 MMbbls of OOIP and the cumulative production represents a
recovery factor of less than 9 percent. The pool has been under a vertical well waterflood and has
facilities necessary to develop the pool using horizontal, multi-frac wells and potentially to improve and
expand the water flood.
Year ended December 31, 2017
Sparky Asset Acquisitions
In 2017, Surge completed two acquisitions of crude oil producing assets in its core Sparky area of Central
Alberta. On April 12, 2017, Surge completed the acquisition of assets producing 745 boe/d (97 percent
crude oil) for a purchase price of $37 million, paid in cash. On September 8, 2017, Surge acquired assets
producing 780 boe/d (95 percent crude oil) for a purchase price of $37.2 million, paid in cash.
Significant Acquisitions
Surge has not completed any “significant acquisitions” (as such term is defined in NI 51-102) during the
financial year ended December 31, 2017.
Overview
DESCRIPTION OF THE BUSINESS
The Corporation is a moderate growth, dividend paying oil and gas exploration, development and
production company. Surge holds focused and operated high quality light and medium gravity crude oil
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properties, primarily in Alberta and Saskatchewan, characterized by large oil in place crude oil reservoirs
with low recovery factors. The Corporation has a significant inventory of low risk development drilling
locations, including several successful water flood projects.
Corporate Strategy
The Corporation is building a moderate growth, dividend paying oil and gas company with focused,
operated light and medium gravity crude oil assets. The Corporation focuses on assets with the following
criteria: large oil in place with low recovery factors, available infrastructure, high working interest,
operatorship, all-season access and drilling inventory, water flood opportunities and other upside that
provides a definable high rate of return.
Management of the Corporation believes in controlling the timing and costs of its projects wherever
possible. Accordingly, the Corporation seeks to become the operator of its properties. Further, to
minimize competition within its geographic areas of interest, the Corporation strives to maximize its
working interest ownership in its properties where reasonably possible.
In reviewing potential drilling or acquisition opportunities, the Corporation gives consideration to the
following criteria: (i) risk capital to secure or evaluate the opportunity; (ii) the potential
the
project, if successful; (iii) the likelihood of success; and (iv) risked return versus cost of capital.
return on
In general, the Corporation pursues a portfolio approach in developing a large number of opportunities
with a balance of risk profiles in an attempt to generate sustainable levels of growth. The Board of
Directors of the Corporation may, in its discretion, approve asset or corporate acquisitions or investments
that do not conform to the guidelines discussed above based upon the Board’s consideration of the
qualitative aspects of the subject properties, including risk profile, technical upside, reserve life and asset
quality.
In addition, the management team of the Corporation, as described below under “Directors and Officers”,
is continually assessing the assets and operations of the Corporation, including its existing land base,
facilities, reserves, prospects and personnel.
Competition
The oil and natural gas industry is competitive in all its phases. The Corporation competes with numerous
other participants in the search for, and the acquisition of, oil and natural gas properties and in the
marketing of oil and natural gas. The Corporation’s competitors include resource companies which have
greater financial resources, staff and facilities than those of the Corporation. Competitive factors in the
distribution and marketing of oil and natural gas include price and methods and reliability of delivery. The
Corporation believes that its competitive position is equivalent to that of other oil and gas issuers of
similar size and at a similar stage of development.
Cyclical and Seasonal Nature of Industry
Surge’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 dramatically during recent years and
are determined by a number of factors, including global and local supply and demand factors, and
including weather and general economic conditions, as well as conditions in other oil and natural gas
producing and consuming regions. Surge attempts to mitigate such price risk through closely monitoring
commodity markets and establishing disciplined hedging programs.
The level of activity in the Canadian oil and natural 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 natural gas producing areas are
- 12 -
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.
Seasonal factors and unexpected weather patterns may lead to declines in exploration and production
activity and corresponding declines in the demand for the goods and services of the Corporation.
Demand for natural gas typically rises during cold winter months and hot summer months.
Environmental Regulation
The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of
provincial and federal legislation. Compliance with such legislation can require significant expenditures or
result in operational restrictions. 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, all of which might have a significant negative impact on earnings and overall
competitiveness. See below under the headings “Industry Conditions - Environmental Regulation” and
“Risk Factors – Environmental Concerns”.
The Corporation is obligated to abandon, retire and reclaim wells and wellsites in compliance with
applicable environmental laws and regulations. As of December 31, 2017, the Corporation has recorded
an asset retirement obligation of $162 million. The Corporation anticipates that the expenditures
necessary to satisfy the asset retirement obligation will be incurred over a period of fifty years, with the
majority of the expenditures being incurred from years 2023 to 2066. Other than asset retirement
obligations and ordinary course operational expenditures necessary to ensure environmental compliance,
the Corporation is not aware of any environmental protection requirement that will impact its capital
expenditures, earnings or competitive position in a manner disproportionate to that of its peers in its area
of operations.
Marketing
Surge’s crude oil and natural gas production are sold primarily through marketing companies at current
market prices. See also “Interest of Management and Others in Material Transactions”.
The Corporation also has a hedging policy as described under “Statement of Reserves Data – Other Oil
and Gas Information – Forward Contracts”. For details of the Corporation’s forward contracts in place as
at December 31, 2017, see the Corporation’s audited annual financial statements for the year ended
December 31, 2017, which have been filed on SEDAR and may be viewed under the Corporation’s profile
at www.sedar.com. See “Risk Factors – Fixed Price Hedging”.
Personnel
As at December 31, 2017, the Corporation had 58 head office employees and 3 field employees.
Health, Safety and Environmental
Management, employees and contractors are responsible and accountable for the overall health, safety
and environmental program. Surge operates in compliance with all applicable regulations and ensures
that all staff and contractors employ sound practices to protect the environment and to ensure employee
and public health and safety.
Surge maintains a safe and environmentally responsible work place and provides training, equipment and
procedures to all individuals in adhering to its policies. It also solicits and takes into consideration input
from neighbors, communities and other stakeholders in regard to protecting people and the environment.
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PRINCIPAL PRODUCING PROPERTIES
The Corporation’s principal oil and natural gas producing properties are located in Alberta and
Saskatchewan and are focused across three core areas: Western Alberta, Southeast Alberta and
Southwest Saskatchewan. A description of those properties, as at December 31, 2017, is provided
below.
Western Alberta
As at December 31, 2017, the Corporation’s principal properties in Western Alberta included
Valhalla/Wembley, Nipisi and Nevis. Surge held an average working interest of approximately 68 percent
in approximately 186,405 gross (126,946 net) developed acres. As at December 31, 2017, the
Corporation held interests in 351 gross (320 net) oil wells and 96 gross (67 net) gas wells producing from,
but not limited to, the Doe Creek, Doig, Montney, Slave Point, Gilwood, Banff, Wabamun, Rock Creek
and Glauc formations. In addition, the Corporation operates multiple oil batteries providing a strong
infrastructure base for future development in the area. As at December 31, 2017, Surge’s fourth quarter
production in Western Alberta was approximately 6,635 boe/d (63 percent oil and NGLs).
Valhalla/Wembley
The Valhalla/Wembley property is located in northwestern Alberta, approximately 40 kilometres northwest
of Grand Prairie. The majority of production from this property was from the horizontal oil wells producing
from an extensive tight sand, with up to 40 metres of gross light oil pay in the Triassic Doig formation.
Additional production is from a shallow, waterflooded, Doe Creek light oil pool.
In 2017, the Corporation drilled 6 gross (4.51 net) Doig horizontal, multi-frac oil wells at Valhalla.
Nipisi
The Nipisi property is located approximately 50 kilometres north of the town of Slave Lake, in
northwestern Alberta. Light oil production is from the Slave Point and Gilwood formations. The Slave
Point production is from horizontal, multi-frac wells and the Gilwood production is from vertical wells.
In 2017 the Corporation continued to optimize its Slave Lake oil pool, including the waterflood on this
property, which had been implemented in 2013 and 2014, with the conversion of 3 wells to injection wells.
Successful incremental waterflood response has been achieved in 2017.
Nevis
The Nevis property is located approximately 60 kilometres east of Red Deer, Alberta. The property is
divided into two main Wabamun oil pools. Crude oil quality for this property averages 39° API and there
is associated natural gas and NGL production. Two operated facilities are utilized to process the oil and
natural gas production from Nevis. The main producing zone is the Devonian age Wabamun Formation,
which occurs at about 1,600 metres true vertical depth.
Southeast Alberta
As at December 31, 2017, Surge’s principal properties in southeastern Alberta included the Sparky
assets and the Lloyd/Cummings zone waterflood at Silver. The Corporation held an average working
interest of approximately 74 percent in approximately 195,407 gross (145,549 net) developed acres and
an average working interest of approximately 77 percent in approximately 49,864 gross (38,570 net)
undeveloped acres. As at December 31, 2017, the Corporation held interests in 638 gross (524 net) oil
wells and 209 gross (170 net) gas wells producing from, but not limited to, the Lloydminster, Sparky,
Cummings, Glauconite, Rex, Dina and Viking formations. In addition, the Corporation operates multiple
oil batteries, providing a strong infrastructure base for future development in the area. As at December
- 14 -
31, 2017, Surge’s fourth quarter production in Southeast Alberta was approximately 5,407 boe/d (91
percent oil and NGLs).
Sparky
The Sparky assets are comprised of six main fields spread between Provost and Wainwright in eastern
Alberta and western Saskatchewan. Eye Hill and Provost are early stage primary development
properties, while Wainwright, Macklin, Lakeview, and East Sounding are more mature, mostly developed
waterflood assets.
In 2017, the Corporation expanded a horizontal waterflood pilot project at Eyehill, after observing
successful waterflood response. In 2017, the Corporation drilled 16 gross (15.78 net) horizontal, multi-
frac, Sparky oil wells and converted two more horizontal wells to injection at Eyehill.
Production from the Sparky is primarily crude oil (89 percent oil and NGLs) ranging from 23° to 28°
degrees API.
In the second quarter of 2017, Surge purchased 745 boepd of Sparky and Manville production and
reserves in the Provost area. The pools purchased contain over 56 MMbbls of OOIP and the cumulative
production represents a recovery factor of less than 17 percent. The pools have been under a vertical
well waterflood and have facilities necessary to develop the pool using horizontal, multi-frac wells and
potentially to improve and expand the waterflood. The production is 100 percent owned and operated, 97
percent oil weighting, with 29 development locations.
In the third quarter of 2017, Surge purchased 780 boepd of Sparky and Manville production and reserves
in the Provost area. The pools purchased contain over 100 MMbbls of OOIP and the cumulative
production represents a recovery factor of less than 16 percent. The pools have been under a vertical
well waterflood and have facilities necessary to develop the pool using horizontal, multi-frac wells and
potentially to improve and expand the waterflood. The production has a 95 percent oil weighting, low
decline of less than 15 percent, with 38 development locations.
Silver
The Silver Lake property is located west of Provost in eastern Alberta. Production from this property is
primarily 24° API Crude oil from the Lloydminster and Cummings formations. The field has been
developed by a mixture of horizontal and vertical wells and is extensively under waterflood.
Southwest Saskatchewan
The Southwest Saskatchewan properties, the majority of which were acquired in July 2013, are primarily
located approximately 100 kilometres southwest of Swift Current, Saskatchewan and 140 kilometres east
of the Alberta border. As at December 31, 2017, this operated property included an average working
interest of approximately 99 percent in approximately 22,356 gross (22,041 net) developed acres and an
average working interest of approximately 98 percent in 15,223 gross (14,943 net) undeveloped acres.
The Corporation’s production from this property is weighted 100 percent to medium crude oil (21-26°
API). The Corporation operates major facilities at this property providing a strong infrastructure base for
future development in the area. As at December 31, 2017, this property’s fourth quarter production was
approximately 2,883 boe/d (100 percent oil) from the Upper and Lower Shaunavon formations.
In 2017, the Corporation continued the development and delineation of the extensive Upper Shaunavon
pool, with the drilling of 17 gross (15.50 net) horizontal, multi-frac, oil wells. The Corporation also
expanded a horizontal, waterflood pilot in the Upper Shaunavon, with the conversion of 4 additional
producing wells to water injection.
- 15 -
STATEMENT OF RESERVES DATA
In accordance with NI 51-101 – Standards for Disclosure for Oil and Gas Activities, Sproule prepared the
Reserves Report based on its evaluation of the oil, NGL and natural gas reserves attributable to the
properties of the Corporation as at December 31, 2017. The Reserves Report is dated February 9, 2018.
The tables below are a combined summary of the oil, NGL and natural gas reserves attributable to the
properties of the Corporation and the net present value of future net revenue attributable to such reserves
as evaluated in the Reserves Report based on forecast price and cost assumptions. The tables
summarize the data contained in the Reserves Report and, as a result, may contain slightly different
numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.
The net present value of future net revenue attributable to reserves is stated without provision for interest
costs and general and administrative costs, but after providing for estimated royalties, production costs,
development costs, other income, future capital expenditures and well abandonment costs for only those
wells assigned reserves by Sproule. It should not be assumed that the undiscounted or discounted net
present value of future net revenue attributable to reserves estimated by Sproule represent the fair
market value of those reserves evaluated. Other assumptions and qualifications relating to costs, prices
for future production and other matters are summarized herein. The recovery and reserve estimates of
oil, NGL and natural gas reserves provided herein are estimates only. Actual reserves may be greater
than or less than the estimates provided herein.
The Reserves Report is based on certain factual data supplied by the Corporation and Sproule’s opinions
of reasonable practice in the industry. The extent and character of ownership and all factual data
pertaining to petroleum properties and contracts (except for certain information residing in the public
domain) were supplied by the Corporation to Sproule. Sproule accepted this data as presented and
neither title searches nor field inspections were conducted.
Summary of Oil and Gas Reserves – Forecast Prices and Costs
Light and
Medium
Crude Oil
(Mbbls)
Heavy
Crude Oil
(Mbbls)
Gross Reserves
Natural
Gas
Liquids
(Mbbls)
Conventional
Natural Gas
(MMcf)
Coalbed
Methane
(MMcf)
Light and
Medium
Crude Oil
(Mbbls)
Heavy
Crude Oil
(Mbbls)
Net Reserves
Natural
Gas
Liquids
(Mbbls)
Conventional
Natural Gas
(MMcf)
Coalbed
Methane
(MMcf)
13,171.7
12,696.3
1,562.3
33,042.0
1,279.0
11,227.9
11,460.4
1,151.2
30,432.0
1,150.0
236.9
13,311.8
26,720.4
16,209.7
1,400.9
6,130.8
20,228.0
10,747.4
26.8
1,467.4
3,056.5
1,483.2
766.0
30,129.0
63,937.0
33,234.0
-
1,534.0
2,813.0
640.0
216.9
11,170.9
22,615.7
12,834.2
1,372.8
5,853.3
18,686.5
9,524.7
18.5
1,212.8
2,382.5
1,132.7
706.0
27,503.0
58,641.0
29,871.0
-
1,445.0
2,595.0
600.0
42,930.1
30,975.4
4,539.7
97,171.0
3,453.0
35,449.8
28,211.2
3,515.1
88,512.0
3,196.0
Proved
Developed
Producing
Developed
Non-
Producing
Undeveloped
Total Proved
Probable
Total Proved
plus Probable
Net Present Value of Future Net Revenue – Forecast Prices and Costs
($M)
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
Before Future Income Tax Expenses and Discounted at
0%
5%
10%
15%
20%
940,019
43,523
686,088
1,669,631
1,300,097
2,969,728
737,123
36,972
486,270
1,260,365
801,350
2,061,715
606,591
31,203
358,162
995,956
556,062
1,552,018
517,242
26,605
271,793
815,640
414,968
1,230,607
452,610
22,985
210,913
686,507
324,792
1,011,299
- 16 -
($M)
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
After Future Income Tax Expenses and Discounted at
0%
5%
10%
15%
940,019
43,523
539,748
1,523,290
952,962
2,476,252
737,123
36,972
390,086
1,164,181
586,563
1,750,744
606,591
31,203
291,992
929,786
407,099
1,336,885
517,242
26,605
224,587
768,434
304,585
1,073,019
20%
452,610
22,985
176,231
651,826
239,426
891,252
Unit Value before Income Tax Discounted
at 10%/year ($/boe)
20.84
18.08
15.53
18.48
19.46
18.82
Additional Information Concerning Future Net Revenue – Forecast Prices and Costs
(Undiscounted)
(Undiscounted) ($M)
Revenue Royalties
Operating
Costs
Develop-
ment
Costs
Abandon-
ment
and Other
Costs
Future net
revenue
before
income
taxes
Future
income
taxes
Future
net
revenue
after
income
taxes
Total Proved
Total Proved plus Probable
3,971,730
6,549,040
475,699
891,220
1,354,559
2,068,762
360,142
485,477
111,698
133,854
1,669,631
2,969,728
146,341
493,475
1,523,290
2,476,252
Future Net Revenue by Production Group – Forecast Prices and Costs
Proved
Light and Medium Crude Oil(1)
Heavy Crude Oil(1)
Conventional Natural Gas(2)
Coalbed Methane(2)
Proved plus Probable
Light and Medium Crude Oil(1)
Heavy Crude Oil(1)
Conventional Natural Gas(2)
Coalbed Methane(2)
Future Net Revenue Before
Income Taxes and
Discounted at 10% per
year ($M)
Per Unit Future Net Revenue Before
Income Taxes and Discounted at
10%(3) per year ($/boe)
624,483
362,856
6,982
1,635
987,133
554,279
8,496
2,111
18.61
19.14
7.39
3.78
18.95
19.38
6.78
3.96
Notes:
1.
2.
3.
Including solution gas and other by-products.
Including by-products, but excluding solution gas from oil wells.
Based on net reserves volumes.
Pricing Assumptions – Forecast Prices and Costs
Sproule employed the following pricing and inflation rate assumptions as of December 31, 2017 in its
evaluation in estimating reserves data using forecast prices and costs. The weighted average historical
prices received by the Corporation for 2017 are also reflected in the table below.
- 17 -
Medium and Light
Crude Oil
Natural
Gas
NGL
Canadian
Light
Sweet
Crude 40
API
($/bbl)
61.84
65.44
74.51
78.24
82.45
84.10
85.78
87.49
89.24
91.03
92.85
94.71
Western
Canada
Select
20.5
API
($/bbl)
48.78
51.05
59.61
64.94
68.43
69.80
71.20
72.62
74.07
75.55
77.06
78.61
Alberta
AECO
Gas Price
($/MMBtu)
2.20
2.85
3.11
3.65
3.80
3.95
4.05
4.15
4.25
4.36
4.46
4.57
Edmonton
Pentanes
plus
($/bbl)
67.21
67.72
75.61
78.82
82.35
84.07
85.82
87.61
89.43
91.29
93.19
95.12
Edmonton
Butane
($/bbl)
44.11
48.73
55.49
57.65
60.12
61.32
62.55
63.80
65.07
66.37
67.70
69.06
Edmonton
Propane
($/bbl)
28.77
26.06
32.84
35.41
37.85
39.29
40.25
41.23
42.23
43.26
44.30
45.36
Operating
Cost
Inflation
rates
(%/Yr)
2.2
0.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
Capital
Cost
Inflation
rates
(%/Yr)
(3.4)
0.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
Exchange
rate
($US/$Cdn)
0.771
0.790
0.820
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
Year
2017 (Surge Actual)
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
Escalated thereafter at a rate of +1.5% per annum.
Reconciliation of Changes in Reserves
The following table sets forth a combined reconciliation of the Corporation’s gross reserves as at
December 31, 2017, derived from the Reserves Report using forecast prices and cost estimates,
reconciled to the gross reserves of the Corporation as at December 31, 2017.
Proved
Balance at December 31,
2016
Product Type Transfer
Extensions and Improved
Recovery
Infill Drilling
Technical Revisions
Acquisitions
Dispositions
Economic Factors
Production
Balance at December 31,
2017
Probable
Balance at December 31,
2016
Product Type Transfer
Extensions and Improved
Recovery
Infill Drilling
Technical Revisions
Acquisitions
Dispositions
Economic Factors
Production
Balance at December 31,
2017
Light and
Medium Crude
Oil (Mbbls)
Heavy Crude
Oil
(Mbbls)
Natural Gas
Liquids
(Mbbls)
Conventional
Natural Gas
(MMcf)
Coalbed
Methane
(MMcf)
Boe
(Mboe)
22,141
16,702
2,726
63,562
2,025
52,501
-
1,382
590
1,891
3,191
(5)
39
(2,508)
26,720
Light and
Medium
Crude
Oil (Mbbls)
-
841
1,405
272
2,689
(109)
63
(1,634)
20,228
-
57
126
352
47
(20)
2
(233)
3,057
-
1,681
2,787
1,309
1,212
(260)
(108)
(6,246)
63,938
-
-
-
996
-
-
(23)
(184)
2,814
-
2,560
2,585
2,899
6,128
(178)
81
(5,447)
61,130
Heavy Crude
Oil
(Mbbls)
Natural Gas
Liquids
(Mbbls)
Conventional
Natural Gas
(MMcf)
Coalbed
Methane
(MMcf)
Boe
(Mboe)
14,540
10,469
1,268
33,519
448
31,938
-
2,384
525
(2,516)
1,225
(1)
54
-
16,210
-
1,297
512
(2,899)
1,381
(27)
15
-
10,747
-
127
134
(76)
21
(6)
15
-
1,483
-
3,313
2,972
(6,508)
547
(72)
(537)
(0)
33,233
-
-
-
205
-
(13)
-
-
640
-
4,360
1,665
(6,542)
2,717
(46)
(8)
(0)
34,086
- 18 -
Proved plus Probable
Balance at December 31, 2016
Product Type Transfer
Extensions and Improved
Recovery
Infill Drilling
Technical Revisions
Acquisitions
Dispositions
Economic Factors
Production
Balance at December 31,
2017
Light and
Medium
Crude
Oil (Mbbls)
36,682
-
3,765
1,115
(625)
4,415
(7)
93
(2,508)
42,930
Heavy Crude
Oil
(Mbbls)
Natural Gas
Liquids
(Mbbls)
Conventional
Natural Gas
(MMcf)
Coalbed
Methane
(MMcf)
27,171
-
2,138
1,916
(2,628)
4,069
(136)
78
(1,634)
30,975
3,994
-
185
259
277
68
(26)
17
(233)
4,540
97,081
-
4,993
5,759
(5,199)
1,759
(332)
(645)
(6,246)
97,171
2,473
-
-
-
1,201
-
-
(37)
(184)
3,453
Boe
(Mboe)
84,439
-
6,921
4,250
(3,643)
8,845
(223)
74
(5,447)
95,216
Additional Information Relating to Reserves Data
Undeveloped Reserves
The following table sets forth the volumes of proved undeveloped reserves that were first attributed in
each of the four most recent financial years and, in the aggregate, before that time:
Proved
Prior to 2013
2013
2014
2015
2016
2017
Light and
Medium Crude
Oil (Mbbls)
8,197.5
6,215.5
4,713.0
1,542.3
2,967.7
1,928.5
Heavy Crude Oil
(Mbbls)
Natural Gas Liquids
(Mbbls)
1,917.8
366.1
166.1
1,199.2
790.6
2,447.2
1,330.4
574.8
268.3
274.5
272.9
101.0
Conventional
Natural Gas
(MMcf)
38,658.9
15,195.3
5,100.0
8,011.0
6,427.0
2,482.0
The following table sets forth the volumes of probable undeveloped reserves that were first attributed in
each of the four most recent financial years and, in the aggregate, before that time:
Probable
Prior to 2013
2013
2014
2015
2016
2017
Light and
Medium Crude
Oil (Mbbls)
Heavy Crude Oil
(Mbbls)
11,217.3
9,567.4
8,526.4
1,241.6
1,915.1
2,067.5
1,140.2
196.5
71.1
1,948.1
1,402.2
1,323.1
Natural Gas
Liquids
(Mbbls)
907.3
350.5
274.0
188.6
183.7
203.9
Conventional
Natural Gas
(MMcf)
30,459.3
9,370.2
5,586.0
5,577.0
4,177.0
4,739.0
Proved undeveloped reserves are generally those reserves related to infill wells that have not yet been
drilled or wells further away from gathering systems requiring relatively high capital to bring on production.
Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be
productive, infill drilling locations and lands contiguous to production. This also includes the probable
undeveloped wedge from the proved undeveloped locations.
The Corporation currently plans to pursue the development of its proven and probable undeveloped
reserves within the next two years through ordinary course capital expenditures. However, the
Corporation may choose to delay development depending on a number of circumstances, including the
existence of higher priority expenditures and prevailing commodity prices and cash flow.
- 19 -
Significant Factors or Uncertainties Affecting Reserves Data
The process of estimating reserves is complex. It requires significant judgments and 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, prices and economic
conditions.
As circumstances change and additional data becomes available, reserve estimates also change.
Estimates made are reviewed and revised, either upward or downward, as warranted by the new
information. Revisions are often required due to changes in well performance, 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. As a result, subjective decisions, new geological or production
information and a changing environment may impact these estimates. Revisions to reserve estimates
can arise from changes in year-end oil and gas prices and reservoir performance. Such revisions can be
either positive or negative.
Future Development Costs
The table below sets out the combined total development costs deducted in the estimation in the
Reserves Report of future net revenue attributable to proved reserves and proved plus probable reserves
(using forecast prices and costs).
2018
2019
2020
2021
2022
Remaining Years
Total Undiscounted
Forecast Prices and Costs
Proved Reserves
($M)
Proved plus
Probable Reserves
($M)
75,076
111,086
129,388
38,024
6,568
-
360,142
82,049
143,373
152,206
84,492
23,096
260
485,477
The Corporation has four sources of funding available to finance its capital expenditure programs:
internally generated cash flow from operations, funds raised from the sale of non-core assets, debt
financing when appropriate and new issues of Common Shares, if available on favourable terms. The
Corporation expects to fund the above future development costs primarily through internally generated
cash flow, funds raised from the sale of non-core assets and debt. There can be no guarantee that the
Board of Directors will allocate funding to develop all of the reserves attributed in the Reserve Reports or
either of them. Failure to develop those reserves could have a negative impact on the Corporation’s
future cash flow.
Other Oil and Gas Information
Oil and Gas Wells
The following table sets forth the number and status of the Corporation’s wells effective December 31,
2017.
Producing
Non-Producing
Oil
Natural Gas
Coalbed
Methane
Water
Inj/Disp
Oil
Natural Gas
Coalbed
Methane
Water
Inj/Disp
- 20 -
Gross
Net Gross
Net Gross
Net Gross
Net Gross
Net Gross
Net Gross
Net
Gross
Net
Alberta
989
735
258
137
Saskatchewan
195
189
67
4
Total
1,184
924
325
141
16
-
16
3
-
3
268
177
1,049
730
575
364
29
27
59
21
33
11
297
204
1,108
751
608
375
-
-
-
-
-
-
209
160
-
-
209
160
Properties with no Attributed Reserves
The following table summarizes, effective December 31, 2017, the gross and net acres of unproved
properties in which the Corporation has an interest and also the number of net acres for which the
Corporation’s rights to explore, develop or exploit will, absent further action, expire within one year.
Alberta
Saskatchewan
Total
Gross
Undeveloped
Acres
Net
Undeveloped
Acres
Net
Undeveloped
Acres Expiring
within One Year
117,458
19,754
137,212
88,879
17,570
106,449
11,557
-
11,557
Additional Information Concerning Abandonment and Reclamation Costs
The Corporation typically estimates well abandonment costs area by area. Such costs are included in the
Reserves Report as deductions in arriving at future net revenue. The expected total abandonment costs
included in the Reserves Report for 907.5 net wells under the proved reserves category is $111.7 million
undiscounted ($17.7 million discounted at 10 percent), of which a total of nil is estimated to be incurred in
2018, 2019 and 2020. This estimate includes expected reclamation costs for surface leases which have
existing wells with economic developed reserves assigned or future development drilling locations. The
Corporation will be liable for its share of ongoing environmental obligations and for the ultimate
reclamation of the properties held by it upon abandonment. Ongoing environmental obligations are
expected to be funded out of cash flow.
Forward Contracts
Surge is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates
and interest rates in the normal course of operations. A variety of derivative instruments are used by
Surge to reduce its exposure to fluctuations in commodity prices and foreign exchange rates. Surge is
exposed to losses in the event of default by the counterparties to these derivative instruments. Surge
manages this risk by diversifying its derivative portfolio amongst a number of financially sound
counterparties.
Based largely upon the Keystone pipeline outage in late 2017, Canadian crude oil differentials widened
beyond the three year historical average of US $13.10 per bbl (i.e. the average for 2015 through 2017).
Surge proactively mitigates the impact of crude oil differentials continuously through numerous light oil
blending initiatives in its Sparky core area. The Corporation has 2,500 bbl per day of WCS differentials
hedged for the first half of 2018 with a cap of US $18 per barrel.
For details of the Corporation’s forward contracts in place as at December 31, 2017, see the
Corporation’s audited annual financial statements for the year ended December 31, 2017, which have
been filed on SEDAR and may be viewed under the Corporation’s profile at www.sedar.com. See “Risk
Factors – Fixed Price Hedging”.
Tax Horizon
Based on planned capital expenditures and the forecast commodity pricing employed in the Reserves
Report, the Corporation estimates that it will not be required to pay current income taxes before 2022.
- 21 -
Costs Incurred
The following table summarizes capital expenditures incurred by the Corporation during the year ended
December 31, 2017.
Property Acquisition Costs
Unproved
Properties
-
Proved
Properties
73,010
Property
Dispositions
(545)
Exploration
Costs
-
Development
Costs
98,466
Total ($M)
Drilling Activity
The following table sets forth the gross and net exploration and development wells drilled by the
Corporation based on rig release date during the year ended December 31, 2017.
Exploration Wells
Gross
Net
Gross
Development Wells
-
-
-
-
-
-
-
-
-
-
-
-
39.00
-
-
-
-
39.00
Net
35.79
-
-
-
-
35.79
Light and Medium Crude Oil
Heavy Crude Oil
Conventional Natural Gas
Service
Dry
Total
Planned Capital Expenditures
The Corporation has announced a planned capital expenditure budget of approximately $98.75 million for
2018.
Production Estimates
The following table discloses for each product type the total volume of production estimated by Sproule in
the Reserves Report for 2017 in the estimates of future net revenue from gross proved and gross proved
plus probable reserves disclosed above.
Light and
Medium
Crude Oil
(bbls/d)
Heavy
Crude Oil
(bbls/d)
Conventional
Natural Gas
(Mcf/d)
Coalbed
Methane
(Mcf/d)
Natural
Gas
Liquids
(bbls/d)
-
3,779
4,075
7,853
-
4,280
4,392
8,671
3,113
1,946
21
5,080
3,437
2,006
22
5,464
-
2,303
16,747
19,050
-
2,705
18,298
21,003
-
-
464
464
-
-
472
472
-
68
806
874
-
79
877
957
Boe
(boe/d)
3,113
6,177
7,770
17,060
3,437
6,815
8,419
18,671
%
18
36
46
100%
18
37
45
100%
Proved
Southwest Saskatchewan
Southeast Alberta
Western Alberta
Total Proved
Proved Plus Probable
Southwest Saskatchewan
Southeast Alberta
Western Alberta
Total Proved Plus Probable
Production History
- 22 -
The following table discloses, on a quarterly basis for the year ended December 31, 2017, certain
information in respect of production, product prices received, royalties paid, operating expenses and
resulting netback for the Corporation.
Average Daily Production Volume
Conventional Natural Gas (Mcf/d)
Light and Medium Crude Oil (bbls/d)
NGL (bbls/d)
Coalbed Methane (Mcf/d)
Total (boe/d)
Mar 31, 2017
Jun 30, 2017
Sep 30, 2017
Dec 31, 2017
Three Months Ended
16,795
10,298
684
507
13,866
17,050
11,522
678
497
15,125
17,458
11,380
627
539
15,007
17,098
12,169
571
509
15,675
Prices Received, Royalties Paid, Production Costs and Netback – Crude Oil
($ per Bbl)
Prices Received
Royalties Paid
Production Costs
Transportation Costs
Netback(1)
Mar 31, 2017
Jun 30, 2017
Sep 30, 2017
Dec 31, 2017
Three Months Ended
43.28
(5.63)
(13.45)
(1.57)
22.64
43.82
(5.57)
(12.74)
(1.48)
24.03
40.66
(5.28)
(13.23)
(1.40)
20.75
47.88
(5.61)
(13.16)
(1.21)
27.90
Note:
1.
Including solution gas and associated natural gas liquids revenue.
Prices Received, Royalties Paid, Production Costs and Netback – Conventional Natural Gas
($ per Mcf)
Prices Received
Royalties Paid
Production Costs
Transportation Costs
Netback
Mar 31, 2017
Jun 30, 2017
Sep 30, 2017
Dec 31, 2017
Three Months Ended
2.08
(0.09)
(3.01)
-
(1.02)
2.06
(0.05)
(1.45)
-
0.56
1.28
0.03
(3.01)
-
(1.69)
0.90
(0.03)
(4.15)
-
(3.29)
Prices Received, Royalties Paid, Production Costs and Netback – Combined
($ per boe)
Prices Received
Royalties Paid
Production Costs
Transportation Costs
Netback(1)
Mar 31, 2017
Jun 30, 2017
Sep 30, 2017
Dec 31, 2017
Three Months Ended
43.63
(5.64)
(13.95)
(1.57)
22.47
44.16
(5.58)
(12.98)
(1.48)
24.12
40.87
(5.27)
(13.73)
(1.40)
20.47
48.03
(5.62)
(13.85)
(1.21)
27.35
Note:
1.
Netback is calculated by deducting royalties paid and production costs, including transportation costs, from
prices received, excluding the effects of hedging.
- 23 -
Production Volume by Field
The following table indicates the average daily net production from the Corporation’s important fields for
the year ended December 31, 2017.
Field
Western Alberta
Southeast Alberta
Southwest Saskatchewan
Sold Properties
Total
Light and
Medium
Crude Oil
(bbls/d)
3,604
4,863
2,883
-3
11,347
Conventional
Natural Gas
(Mcf/d)
Natural Gas
Liquids
(bbls/d)
Coalbed
Methane
(Mcf/d)
14,222
2,880
-
-
17,102
575
64
-
-
639
513
-
-
-
513
Boe
(boe/d)
6,635
5,407
2,883
-3
14,922
%
44
36
19
0
100%
- 24 -
DESCRIPTION OF CAPITAL STRUCTURE
Share Capital
The Corporation is authorized to issue an unlimited number of Common Shares and an unlimited number
of preferred shares, issuable in series.
Common Shares
The holders of Common Shares are entitled to: (i) one vote for each Common Share held at all meetings
of shareholders of the Corporation other than meetings of the holders of any class or series of shares
meeting as a class or series; (ii) receive any dividends declared by the Corporation on the Common
Shares; and (iii) subject to the rights of shares ranking prior to the Common Shares, to receive the
remaining property of the Corporation on dissolution, after the payment of all liabilities.
Preferred Shares
Preferred shares may be issued in one or more series. The Board of Directors is authorized to fix the
number of shares in each series and to determine the designation, rights, privileges, restrictions and
conditions attached to the shares of each series. Preferred shares of the Corporation are entitled to a
priority over the Common Shares with respect to the payment of dividends and the distribution of assets
upon the liquidation, dissolution or winding-up of The Corporation.
Debentures
The Debentures are issued under and pursuant to the provisions of the indenture (the “Indenture”)
among Computershare Trust Company of Canada and Surge. The following is a summary of the material
attributes and characteristics of the Debentures. This summary does not purport to be complete and is
subject to and qualified in its entirety by reference to the terms of the Indenture which may be viewed
under Surge’s profile on SEDAR at www.sedar.com.
The Debentures will mature and be repayable on December 31, 2022 (the “Maturity Date”) and will
accrue interest at the rate of 5.75% per annum payable semi-annually in arrears on December 31 and
June 30 of each year (each an “Interest Payment Date”), commencing on June 30, 2018 and computed
on the basis of a 365-day year. The June 30, 2018 interest payment will represent accrued interest for
the period from and including November 15, 2017 up to, but excluding, June 30, 2018. Interest on the
Debentures will be payable in lawful money of Canada.
At the holder’s option, the Debentures may be converted into Common Shares at any time prior to 5:00
p.m. (Calgary time) on the earlier of the business day immediately preceding (i) the Maturity Date; and (ii)
if called for redemption, the date fixed for redemption by the Corporation, at a conversion price of $2.75
per Common Share, subject to adjustment in certain events (the “Conversion Price”). This represents a
conversion rate of approximately 363.6364 Common Shares for each $1,000 principal amount of
Debentures, subject to certain anti-dilution provisions. Holders who convert their Debentures will receive,
in addition to the applicable number of Common Shares, accrued and unpaid interest in respect thereof
for the period up to, but excluding, the date of conversion from, and including, the most recent Interest
Payment Date. If a holder elects to convert its Debentures in connection with a change of control that
occurs prior to the Maturity Date, the holder will be entitled to receive additional Common Shares as a
make-whole premium on conversion in certain circumstances (as more fully described in the Indenture).
The Debentures are direct, subordinated, unsecured obligations of the Corporation, subordinated to any
existing and future senior indebtedness of the Corporation and ranking equally with one another and with
all other existing and future subordinated unsecured indebtedness of the Corporation to the extent
subordinated on the same terms.
- 25 -
The Debentures may not be redeemed by the Corporation prior to December 31, 2020 except in certain
circumstances following a change of control. On and after December 31, 2020 and prior to December 31,
2021, the Debentures may be redeemed by the Corporation, in whole or in part, from time to time, on not
more than 60 days and not less than 30 days prior written notice at a redemption price equal to their
principal amount plus accrued and unpaid interest, if any, up to but excluding the date set for redemption,
provided that the volume weighted average trading price of the Common Shares on the TSX for the 20
consecutive trading days ending five trading days prior to the date on which notice of redemption is
provided is at least 125 percent of the Conversion Price. On or after December 31, 2021 and prior to the
Maturity Date, the Debentures may be redeemed by the Corporation, in whole or in part, from time to
time, on not more than 60 days and not less than 40 days prior notice at a redemption price equal to their
principal amount plus accrued and unpaid interest, if any, up to but excluding the date set for redemption.
The Debentures were listed and posted for trading on the TSX under the symbol “SGY.DB” at the open of
markets on November 15, 2017.
DIVIDEND POLICY
On July 3, 2013, in connection with the Corporation’s transition to a sustainable, moderate growth,
dividend paying oil and gas company, the Board adopted a policy of paying monthly dividends. The
primary objective of the Corporation’s dividend policy is to provide shareholders with relatively stable,
predictable and sustainable monthly dividends.
On January 7, 2015, as a result of the precipitous drop in crude oil prices from US$106 WTI per barrel in
June 2014 to a low of US$45 WTI in January 2015, the Board approved a reduction of the dividend to
$0.30 per annum ($0.025 monthly). On November 9, 2015, as a result of the continued weakness of
crude oil prices, the Board approved a further reduction of the dividend to $0.15 per annum ($0.0125
monthly). On April 7, 2016, the Board approved a further reduction of the dividend to $0.075 per annum
(0.00625 monthly).
On February 15, 2017, the Board approved an increase of the dividend to $0.085 per annum ($0.00708
monthly). On May 15, 2017, the Board approved a further increase of the dividend to $0.095 per annum
($0.007917 monthly).
The agreement with respect to the Credit Facility contains certain restrictions on Surge’s ability to pay
dividends in certain circumstances. In addition, the payment of dividends by a corporation is governed by
the liquidity and insolvency tests described in the ABCA. Pursuant to the ABCA, after the payment of a
dividend, a corporation must be able to pay its liabilities as they become due and the realizable value of
the assets of the corporation must be greater than the liabilities and the legal stated capital of its
outstanding securities.
The following monthly cash dividends on Common Shares were declared for the periods indicated:
Dividends per Common Share
2018
0.007917
0.007917
0.007917
Month
January
February
March
April
May
June
July
August
September
October
November
2016
0.0125
0.0125
0.0125
0.00625
0.00625
0.00625
0.00625
0.00625
0.00625
0.00625
0.00625
2015
0.025
0.025
0.025
0.025
0.025
0.025
0.025
0.025
0.025
0.025
0.0125
2017
0.00625
0.00708
0.00708
0.00708
0.007917
0.007917
0.007917
0.007917
0.007917
0.007917
0.007917
- 26 -
December
Total
$0.024
0.007917
$0.091
0.00625
$0.094
0.0125
$0.275
Unless otherwise specified, all dividends paid or to be paid are designated as “eligible dividends” under
the Income Tax Act (Canada).
There can be no guarantee that the Corporation will maintain its dividend policy. The amount of
cash dividends to be paid on the Common Shares, if any, will be subject to the discretion of the
Board of Directors and may vary depending on a variety of factors, including the prevailing
economic and competitive environment, results of operations, fluctuations in working capital, the
price of oil and gas, the taxability of the Corporation, the Corporation’s ability to raise capital, the
amount of capital expenditures, the satisfaction of solvency tests imposed by the ABCA for the
declaration and payment of dividends, applicable law and other factors. Additionally, the
agreement with respect to the Credit Facility contains certain restrictions on Surge’s ability to pay
dividends in certain circumstances. See “Risk Factors – Dividends”.
MARKET FOR SECURITIES
The Common Shares are listed and posted for trading on the TSX under the trading symbol “SGY”. The
following table sets forth the market price ranges and the trading volumes for the Common Shares for the
periods indicated, as reported by the TSX, for the year ended December 31, 2017.
Price Range ($)
Period
2017
January
February
March
April
May
June
July
August
September
October
November
December
High
3.45
2.91
2.73
2.91
2.65
2.33
2.25
2.22
2.37
2.24
2.39
2.12
Low
2.80
2.48
2.30
2.44
2.21
1.91
1.94
1.91
1.96
1.92
1.95
1.90
Trading
Volume
22,283,553
22,926,939
25,220,279
33,383,408
20,219,643
39,073,031
11,924,057
10,777,698
12,898,164
11,320,051
21,083,713
14,439,544
The Debentures are listed and posted for trading on the TSX under the trading symbol “SGY.DB”. The
following table sets forth the market price ranges and the trading volumes for the Debentures for the
periods indicated, as reported by the TSX, for the year ended December 31, 2017.
Price Range ($)
Period
High
Low
Trading
Volume
2017
November (from
November 15)
December
100.10
98.00
13,795,910
101.00
98.00
6,477,000
Note:
1.
The Debentures were listed and posted for trading on the TSX under the symbol SGY.DB at the open of
markets on November 15, 2017.
- 27 -
DIRECTORS AND OFFICERS
The name, municipality of residence, principal occupation for the prior five years and position with the
Corporation of each of the directors and officers of the Corporation are as follows:
Position
Principal Occupation During Previous Five Years
Name and
Residence
Paul Colborne
Calgary, Alberta
President and
Chief Executive
Officer
Director since
April 13, 2010
President and CEO of the Corporation. He is also the President of
StarValley Oil and Gas Ltd., a private, Calgary-based oil and gas
company founded in November 2005. Mr. Colborne currently
serves on the Board of Directors of Rising Star Resources Ltd., a
private oil and gas company, and until its sale in February 2018,
served on the Board of Directors of Red River Oil Inc., a private oil
and gas company. In 1993, after nine years practicing securities,
banking and oil and gas law, Mr. Colborne directed his focus to the
oil and gas industry and founded an oil and gas company called,
Startech Energy Ltd., a publicly traded company, which grew to
15,000 boe/d. Eight years later in 2001, Startech was acquired by
ARC Energy Trust for more than C$500 million. From September
2003 to January 2005, Mr. Colborne was the President and CEO of
StarPoint Energy Trust, a 36,000 boe/d publicly traded energy trust.
From 1996 to May of 2013, Mr. Colborne was on the Board of
Crescent Point Energy, a 165,000 boe/d, publicly traded, dividend
paying oil and gas company. Until its sale in July of 2009, Mr.
Colborne served as Chairman of TriStar Oil & Gas Ltd. He was also
a Director for Westfire Energy Ltd., Twin Butte Energy Ltd.,
Cequence Energy, and Chairman of Seaview Energy Ltd. until its
sale in December of 2009, he also served as a Director of Breaker
Energy. Mr. Colborne was also Chairman and a Director of Mission
Oil and Gas Inc. until its sale in February 2007. In May of 2014,
Paul stepped down from the Board of Legacy Oil + Gas. In June of
2014, Paul completed his term as Chairman of a private company
called New Star Energy Ltd., and stepped down as a Director.
Independent businessperson since his retirement on May 8, 2013.
Prior
the
thereto, President and Chief Executive Officer of
Corporation since April 13, 2010. Prior thereto, President and Chief
Executive Officer of Breaker Energy Ltd., a publicly traded oil and
natural gas company, from its formation in September 2004 until its
acquisition by NAL Oil & Gas Trust in December 2009. Mr. O’Neil
was also a director of Cathedral Energy Services Ltd. Prior to its
sale, Mr. O’Neil was also a director of Hyperion Exploration Corp.
P. Daniel
O’Neil(3)(4)
Calgary, Alberta
Director since
April 13, 2010
Robert
Leach(1)(2)
Phoenix,
Arizona
Director since
April 13, 2010
Chief Executive Officer of Custom Truck Sales Ltd., a private
company operating Kenworth truck dealerships in Saskatchewan
and Manitoba, and Vice President of ReNue Properties Arizona Inc.
Mr. Leach was formerly the Chairman of the Board of Breaker
Energy Inc.
Keith
Macdonald(1)(3)(4)
Calgary, Alberta
Director since
April 13, 2010
President of Bamako Investment Management Ltd., a private
holding and financial consulting company. Mr. Macdonald is also
Chief Executive Officer and Director of EFLO Energy Inc. and a
director of Bellatrix Exploration Ltd., a company listed on the TSX.
As well, he is a director of Mountainview Energy Ltd., which is listed
- 28 -
Name and
Residence
Position
Principal Occupation During Previous Five Years
James Pasieka
Calgary, Alberta
Director since
April 13, 2010
Chairman of
the Board since
January 7,
2015
Murray
Smith(1)(2)
Calgary, Alberta
Director since
June 25, 2010
Daryl Gilbert(2)(3)
Calgary, Alberta
Director since
June 5, 2014
Paul Ferguson
Calgary, Alberta
Chief Financial
Officer
on the TSX Venture Exchange, and other public and private oil and
gas companies. Mr. Macdonald has served as an officer and
director of a number of public and private energy companies.
Partner of the national law firm McCarthy Tétrault LLP since
September 2013. Prior thereto, partner of the national law firm
Heenan Blaikie LLP since 2001. Mr. Pasieka has served as an
officer and director of a number of public energy companies, and
chairman of the board of several oil and gas companies.
President of Murray Smith and Associates. Mr. Smith also serves
on the board of two private companies and Williams Companies
Inc. (WMB.nyse), a Tulsa based midstream company. Prior
thereto, Mr. Smith was an Official Representative of the Province of
Alberta to the United States of America until 2007. Prior thereto, he
was a member of the Legislative Assembly in the Province of
Alberta serving in four different Cabinet portfolios – Energy,
Gaming, Labour, and Economic Development from 1993 to 2005.
Chair of the Reserves Committee for the Corporation. Managing
Director and Investment Committee member of JOG Capital Inc.
since May 2008. Mr. Gilbert has also been an independent
businessman and investor, and serves as a director for a number of
public and private entities, since 2005. Mr. Gilbert has been active
in the Western Canadian oil and natural gas sector for over 40
years, working in reserves evaluation with Gilbert Laustsen Jung
Associates Ltd. (now GLJ Petroleum Consultants Ltd.) (“GLJ”), an
engineering consulting firm, from 1979 to 2005. Mr. Gilbert served
as President and Chief Executive Officer of GLJ from 1994 to 2005.
Chief Financial Officer of the Corporation since September 2015.
Prior thereto, Mr. Ferguson was a research analyst at Fidelity
Investments from December 2012. Prior thereto, Mr. Ferguson was
a research analyst at Surveyor Capital from May 2011 to December
2012. Prior thereto, Mr. Ferguson was a portfolio manager and
analyst at Swank Capital, LLC.
Margaret Elekes
Calgary, Alberta
Vice-President,
Land and
Business
Development
Vice-President, Land of the Corporation. Prior thereto, Consulting
Landman for Breaker Energy from its formation in September 2004
until its acquisition by NAL Oil & Gas Trust in December 2009. Prior
thereto, US Land Manager for Upton Resources from December
1995 until its acquisition by StarPoint Energy in February 2004.
Murray Bye
Calgary, Alberta
Vice-President,
Production
Vice-President, Production of the Corporation since May 8, 2013.
Prior thereto, Asset Team Lead - West at Surge since 2010. Prior
to his role at Surge, Mr. Bye held a number of positions at EnCana
Corporation between the years 2000 to 2010 including: Group Lead
of Development, Exploitation Engineer, and Production Engineer.
- 29 -
Notes:
1.
2.
3.
4.
Member of the Audit Committee.
Member of the Compensation, Nominating and Corporate Governance Committee of the Board.
Member of the Reserves Committee of the Board.
Member of the Environment, Health and Safety Committee of the Board.
As at March 14, 2018, the directors and executive officers of the Corporation, as a group, beneficially
own, control or direct, directly or indirectly, 8,175,893 Common Shares, representing approximately 3.5
percent of the outstanding Common Shares.
The terms of office of each of the directors of the Corporation will expire at the next annual general
meeting of the shareholders of the Corporation.
Cease Trade Orders, Bankruptcies, Penalties or Sanctions
Other than as set forth below, to the knowledge of management of the Corporation:
a)
b)
c)
no director or executive officer of the Corporation is, or within the 10 years before the date of this
AIF, has been, a director, chief executive officer or chief financial officer of any other issuer that:
(i) was the subject of a cease trade or similar order or an order that denied the other issuer
access to any exemptions under Canadian securities legislation that lasted 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 that lasted 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 the person was acting in the
capacity as director, chief executive officer or chief financial officer;
no director or executive officer, or any shareholder holding a sufficient number of securities of the
Corporation to affect materially the control of the Corporation, or a personal holding company of
any such person: (i) is, at the date of this AIF or has been within the 10 years before the date of
this AIF, a director or executive officer of any company that, while that 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 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; or (ii) has, within the 10 years before the date of this AIF,
become bankrupt, made a proposal under any legislation 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 the assets of the director, officer or
shareholder; and
no director or executive officer, or any shareholder holding a sufficient number of securities of the
Corporation to affect materially the control of the Corporation, has: (i) been subject to any
penalties or sanctions imposed by a court relating to Canadian securities legislation or by a
Canadian securities regulatory authority or has entered into a settlement agreement with the
Canadian securities regulatory authority; or (ii) been subject to 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.
Mr. Gilbert was a director of Globel Direct Inc (“Globel Direct”) which sought and received protection
under the Companies’ Creditors Arrangement Act (Canada) in June 2007, and after a failed restructuring
effort, a receiver was appointed by one of Globel Direct’s lenders in December 2007. Cease trade orders
in respect of Globel Direct were issued for failure to file financial statements when due.
- 30 -
Mr. Gilbert has been a director of Connacher Oil & Gas Limited (“Connacher”) since October of 2014.
On May 17, 2016, Connacher applied for and was granted protection from its creditors by the Court of
Queen's Bench of Alberta pursuant to the Companies’ Creditors Arrangement Act (Canada). Cease trade
orders were issued in respect of Connacher immediately following the Court Order. A restructuring
process is currently underway.
Mr. Gilbert was also a director of LGX Oil + Gas Inc. (“LGX”), a public company with shares trading on the
TSX Venture Exchange, which was placed into receivership in June 2016 and, in connection therewith, a
receiver was appointed under the Bankrutpcy and Insolvency Act (Canada). Mr. Gilbert resigned as a
director of LGX immediately following the appointment of the receiver. Cease trade orders in respect of
LGX were issued shortly after the appointment of the receiver.
Mr. Macdonald is a director of Mountainview Energy Ltd. (“Mountainview”), a public company with
shares trading on the TSX Venture Exchange. A cease trade order in respect of Mountainview was
issued by the Alberta Securities Commission on May 5, 2016 for failure to file its annual continuous
disclosure filings for the fiscal period ended December 31, 2015. As of the date hereof, the order remains
in effect. Subsequently on October 14, 2016, a wholly-owned subsidiary of Mountainview filed a
voluntary petition under Chapter 11 of the United States Bankruptcy Code.
Mr. Pasieka was also a director of LGX. Mr. Pasieka resigned as a director of LGX in July 2015. LGX was
placed into receivership nearly twelve months later in June 2016 and, in connection therewith, a receiver
was appointed under the Bankrutpcy and Insolvency Act (Canada). Cease trade orders in respect of LGX
were issued shortly after the appointment of the receiver.
Conflicts of Interest
As at the date hereof, the Corporation is not aware of any existing or potential material conflicts of interest
between the Corporation and a director or officer of the Corporation.
Composition of the Audit Committee, Charter and Review of Services
AUDIT COMMITTEE
The Audit Committee of the Board of Directors operates under a written charter that sets out its
responsibilities and composition requirements. A copy of the charter is attached to this AIF as Schedule
“C”.
The members of the Audit Committee of the Board of Directors are Keith Macdonald (Chair), Murray
Smith and Robert Leach. The Audit Committee charter requires all members of the Audit Committee to be
“financially literate” and “independent” within the meaning of applicable securities laws. All members of
the Audit Committee meet these requirements. The relevant education and experience of each Audit
Committee member is outlined below:
Name
Independent
Financially
Literate
Relevant Education and Experience
Keith
Macdonald
(cid:1)
(cid:1)
Mr. Macdonald is currently the President of Bamako
Investment Management Ltd., a private holding and
financial consulting company. Mr. Macdonald is a
director of Bellatrix Exploration Ltd. and Mountainview
Energy Ltd.
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Name
Independent
Financially
Literate
Relevant Education and Experience
Murray Smith
(cid:1)
(cid:1)
Robert Leach
(cid:1)
(cid:1)
He has served as chair and/or a member of the audit
committee of each of those companies, as well as
several other public oil and gas companies for which he
has been a director. Mr. Macdonald was also formerly a
director of Breaker Energy Ltd. prior to its sale in 2009.
From 1994 to January 1999, Mr. Macdonald was vice
president of finance and a director of New Cache
Petroleum Ltd. Mr. Macdonald founded New Cache
Petroleum Ltd. in 1988 and was its president until a
merger in 1994.
Mr. Macdonald holds
the Chartered Accountants
designation, achieved in 1980, and a Bachelor of
Commerce degree (Accounting and Finance Major) from
University of Calgary in 1978.
President of Murray Smith and Associates and director
of Williams Companies Inc. (WMB.nyse). Mr. Smith also
serves on the board of two private companies. Prior
thereto, Mr. Smith was an Official Representative of the
Province of Alberta to the United States of America until
2007. Prior thereto, he was a member of the Legislative
Assembly in the Province of Alberta serving in four
different Cabinet portfolios – Energy, Gaming, Labour,
and Economic Development from 1993 to 2005.
From 1998-2004 Mr. Smith was a member of the
Government of Alberta Treasury Board (responsible for
the annual budget for Alberta) and a contributing
member to Alberta’s debt elimination in 2004.
Mr. Smith has a degree in Economics from the
University of Calgary (1971) and is a graduate of the
London Business School Senior Executive Program
(2000).
Mr. Leach is currently the Chief Executive Officer of
Custom Truck Sales Ltd., a private company operating
Kenworth
in Saskatchewan and
Manitoba, and Vice President of ReNue Properties
Arizona Inc. Mr. Leach was formerly the Chairman of
the Board of Breaker Energy Inc.
truck dealerships
Mr. Leach has experience reviewing and assessing
financial statements from his tenure on the audit
committee of Breaker, as a member of the Board of
Surge, and through his years of experience at Custom
Truck Sales Ltd. and International Fitness Holdings.
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Name
Independent
Financially
Literate
Relevant Education and Experience
Mr. Leach holds a Bachelor of Commerce from the
College of Commerce at the University of Saskatchewan
where he majored in Accounting (1982). Mr. Leach
articled with KPMG LLP and left to start a private
business in 1983.
Pre-Approval of Policies and Procedures
The Audit Committee charter requires that any non-audit services by the Corporation’s auditors must be
pre-approved by the Audit Committee. The Audit Committee has passed a resolution providing the
Chairman of the Audit Committee with delegated authority to approve the provision of non-audit services
by the Corporation’s auditors from time to time, provided that: (i) such services are provided pursuant to a
written engagement letter setting out the services to be provided and the applicable fees; (ii) the provision
of such services is otherwise in compliance with the Audit Committee’s charter; (iii) such services could
not be reasonably seen to result in the auditors performing any management function, auditing their own
work or serving in an advocacy role on behalf of the Corporation; (iv) the fees for such services do not
exceed $50,000 per engagement; and (v) the Chairman reports to the Committee at the next regularly
scheduled meeting any approval of non-audit services made pursuant to the authority delegated under
the resolution. The Audit Committee also pre-approves all audit services and the fees to be paid.
External Auditor Service Fees
KPMG LLP are the auditors of the Corporation. KPMG LLP have been the auditors of the Corporation
since May 5, 2010.
The following table sets out the aggregate fees billed by KPMG LLP to the Corporation in each of the last
two fiscal years.
Year
2017
2016
Audit Fees(1)
$195,000
$201,000
Audit-Related
Fees
$64,000
$20,000
Tax Fees(2)
All Other Fees
$90,000
$113,500
$60,000
$0
Notes:
1.
2.
Audit fees consist of fees for the audit of annual financial statements or services that are normally provided
in connection with statutory and regulatory filings or engagements. The services provided in this category
included quarterly review fees.
Fees for tax compliance, tax advice and tax planning.
Restrained Pipeline Capacity and Differential Volatility
INDUSTRY CONDITIONS
Western Canada has seen significant growth in crude production volumes over recent years. This has
resulted in pressure on the pipeline take-away capacity, leading to apportionment on the main lines and,
in turn, backed-up local feeder pipelines. This has contributed to a widening of, and increased volatility
in, the light oil pricing differential between WTI and Edmonton Par and the medium/heavy crude oil pricing
differential between WTI and Cromer/WCS/Hardisty. Although pipeline expansions are ongoing and
producers are increasingly turning to rail as an alternative means of transportation, the lack of firm
pipeline capacity continues to affect the oil and natural gas industry in Western Canada and limit the
ability to produce and to market production. In addition, the pro-rationing of capacity on the interprovincial
pipeline systems also continues to affect the ability to export oil and natural gas.
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Under the Canadian constitution, interprovincial and international pipelines fall within the federal
government's jurisdiction and require approval by both the National Energy Board of Canada (“NEB”) and
the cabinet of the federal government. However, recent years have seen a perceived lack of policy and
regulatory certainty at a federal level. Although the current federal government recently introduced draft
legislation to amend the current federal approval processes, it is uncertain when the new legislation will
be brought into force and whether any changes to the draft legislation will be made before the legislation
is brought into force. It is also uncertain whether any new approval process adopted by the federal
government will result in a more efficient approval process. The lack of regulatory certainty is likely to
have an influence on investment decisions for major projects. Even when projects are approved on a
federal level, such projects often face further delays due to interference by provincial and municipal
governments as well as court challenges on various issues such as indigenous title, the government's
duty to consult and accommodate indigenous peoples and the sufficiency of environmental review
processes, which creates further uncertainty. Export pipelines from Canada to the United States face
additional uncertainty as such pipelines require approvals of several levels of government in the United
States.
Legislation and Regulation
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 Saskatchewan, all of
which should be carefully considered by investors in the oil and natural gas industry. It is not expected
that any of these controls or regulations will affect the operations of Surge in a manner materially different
than they would affect other oil and natural gas producers of similar size. All current legislation is a
matter of public record and Surge is unable to predict what additional legislation or amendments may be
enacted. Some of the principal aspects of legislation, regulations and agreements governing the oil and
natural gas industry are described further below.
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. Oil prices are primarily based on worldwide supply and
demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market,
the value of refined products, the supply/demand balance, and contractual terms of sale. Oil exporters are
also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil
and two years in the case of heavy crude oil, provided that an order approving such export has been
obtained from the NEB. Any oil export to be made pursuant to a contract of longer duration (to a
maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of
such a licence requires a public hearing and the approval of the Governor in Council.
On July 6, 2012, the federal government enacted the Jobs, Growth and Long-term Prosperity Act which
made amendments to the National Energy Board Act (“NEB Act”) that affect the NEB’s export and import
framework. As a result of these changes, the NEB issued the Interim Memorandum of Guidance
Concerning Oil and Gas Export Applications and Gas Import Applications under Part VI of the National
Energy Board Act (“Interim Oil and Gas MOG”). The purpose of the Interim Oil and Gas MOG is to
provide guidance to applicants until such time as the NEB has completed the review and update of the
regulatory framework. As part of the review and update, the NEB is currently proposing amendments to
the National Energy Board Part VI (Oil and Gas) Regulations and the National Energy Board Export and
Import Reporting Regulations.
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
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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.
The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported
from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to
negotiate prices and other terms with purchasers, provided that the export contracts must continue to
meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than
propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in
quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order. Any natural gas
export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger
quantity requires an exporter to obtain an export licence from the NEB and the issuance of such a licence
requires a public hearing and the approval of the Governor in Council.
The government of Alberta also regulates the volume of natural gas that may be removed from the
province for consumption elsewhere based on such factors as reserve availability, transportation
arrangements, and market considerations. Natural gas prices in Alberta have been constrained in recent
years due to increasing supply in North America, limited access to markets and limited storage capacity.
The North American Free Trade Agreement
The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the United
States and Mexico came into force on January 1, 1994. In the context of energy resources, Canada
continues to remain free to determine whether exports of energy resources to the United States or Mexico
will be allowed, provided that any export restrictions do not: (i) 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; (ii) impose an export price higher than the
domestic price (subject to an exception with respect to certain measures which only restrict the volume of
exports); and (iii) disrupt normal channels of supply.
All three signatory countries are prohibited from imposing a minimum or maximum export price
requirement in any circumstance where any other form of quantitative restriction is prohibited. The
signatory countries are also prohibited from imposing a minimum or maximum import price requirement
except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA
requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes
and to ensure that the application of those changes will cause minimal disruption to contractual
arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of
which are important for Canadian oil and natural gas exports. NAFTA contemplates the reduction of
Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions
and export taxes.
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The new administration in the United States has indicated an intention to seek renegotiation of NAFTA,
the impact of which on the oil and gas industry is uncertain. Canada, the United States and Mexico began
renegotiating the terms of NAFTA in mid-2017. The United States has also suggested that it might give
notice of the termination of NAFTA if it is not satisfied with the outcome of the renegotiations. As of the
date hereof, renegotiation discussions continue and the outcome of such negotiations remains unclear.
As the United States remains Canada's largest trade partner and the largest international market for the
export of crude oil, natural gas and NGLs from Canada, any changes to, or termination of, NAFTA could
have an impact on Western Canada's crude oil and natural gas industry, including Surge’s business.
Trans-Pacific Partnership
Canada and ten other countries recently concluded discussions and agreed on the draft text of the
Comprehensive and Progressive Agreement for Trans-Pacific Partnership ("CPTPP"), which is intended
to allow for preferential market access among the countries that are parties to the CPTPP. The text of
CPTPP has not been finalized or published and the agreement remains subject to ratification by the
governments of each of the countries involved.
Other Trade Agreements
Canada has also pursued a number of other international free trade agreements with countries around
the world. 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.
While it is uncertain what effect CETA, 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 (“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 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. Payments to aboriginal governments are exempt
from reporting obligations until 2017. Failure to comply with the reporting obligations under ESTMA are
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 $9,000,000 in total liability.
Provincial Royalties and Incentives
General
In addition to federal regulation, each province has legislation and regulations that govern land tenure,
royalties, production rates, environmental protection and other matters. The royalty regime is a significant
factor in the profitability of crude oil, natural gas, natural gas liquids and sulphur production. Royalties
payable on production from lands other than Crown lands are determined by negotiations between the
mineral owner and the lessee, although production from such lands is also subject to certain provincial
taxes and royalties. Operations not on Crown lands and subject to the provisions of specific agreements
are also usually subject to royalties negotiated between the mineral owner and the lessee. These
royalties are not eligible for incentive programs sponsored by various governments as discussed below.
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Crown royalties are determined by governmental regulation and are generally calculated as a percentage
of the value of the 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 from time
to time 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.
From time to time the governments of the Western Canadian provinces have established incentive
programs for exploration and development. Such programs often provide for royalty rate reductions,
royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or
enhanced recovery projects. The programs are designed to encourage exploration and development
activity by improving earnings and cash flow within the industry.
Producers and working interest owners of crude oil and natural gas rights may also carve out additional
royalties or royalty-like interests through non-public transactions, which include the creation of
instruments such as overriding royalties, net profits interests and net carried interests.
Alberta
Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments,
currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural
gas produced from Crown Lands. Producers of oil and natural gas from Crown lands in Alberta are also
required to pay a royalty on substances produced from Crown lands.
On May 27, 2010, the Government of Alberta announced changes to the existing royalty framework under
the Petroleum Royalty Regulation, 2009 and the Natural Gas Royalty Regulation, 2009 which became
effective January 1, 2011 (the “Alberta Royalty Framework”). Changes include making the Natural Gas
Deep Drilling Program, which adjusts the royalties for deep gas wells, a permanent initiative under the
Alberta Royalty Framework. Qualifying wells under the Natural Gas Deep Drilling Program include
natural gas wells with gas-oil ratios of greater than 1,800:1 which have been spud or deepened on or
after May 1, 2010 and have a true vertical depth greater than 2,000 metres. An Emerging Resources and
Technologies Initiative has also been created to encourage new exploration and development from higher
cost and more technically challenging resources, such as shale gas, coal seams and horizontal oil and
gas wells. In particular, pursuant to the Emerging Resource and Technologies Initiative: (a) coalbed
methane wells will receive a maximum royalty rate of 5 percent for 36 producing months on up to 750
MMcf of production, retroactive to wells that began producing on or after May 1, 2010; (b) shale gas wells
will receive a maximum royalty rate of 5 percent for 36 producing months with no limitation on production
volume, retroactive to wells that began producing on or after May 1, 2010; (c) horizontal gas wells will
receive a maximum royalty rate of 5 percent for 18 producing months on up to 500 MMcf of production,
retroactive to wells that commenced drilling on or after May 1, 2010; and (d) horizontal oil wells and
horizontal non-project oil sands wells will receive a maximum royalty rate of 5 percent with volume and
production month limits set according to the depth (including the horizontal distance) of the well,
retroactive to wells that commenced drilling on or after May 1, 2010.
On January 29, 2016, the Alberta government announced changes to the Alberta Royalty Framework.
Under the new modern royalty framework (the “MRF”), the sliding scale royalty concept will be
maintained, but will be achieved with a greater degree of simplicity. The new royalty percentage will be
applied to the gross revenue generated from all hydrocarbons, with no differentiation between produced
substances, and wells will be charged a flat 5 percent royalty rate until revenues exceed a normalized
well cost allowance, which will be based on vertical well depth and lateral length. The calculation of this
cost allowance, and other details regarding the various parameters within the new formula under the MRF
was announced in 2016 and was fully implemented as of January 1, 2017. Prior to January 1, 2017, the
former royalty framework continued to apply to any wells drilled prior to that date, and thereafter for a
period of 10 years following which, such wells will be transitioned into the MRF.
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In addition to any negotiated royalty amount payable to the freehold mineral owner, producers of oil and
natural gas from freehold lands in Alberta are required to pay annual freehold mineral taxes. The freehold
mineral tax is a tax levied by the Government of Alberta on the value of oil and natural gas production
from non-Crown lands and is derived from the Freehold Mineral Rights Tax Act (Alberta). The freehold
mineral tax is levied on an annual basis on calendar year production using a tax formula that takes into
consideration, among other things, the amount of production, the hours of production, the value of each
unit of production, the tax rate and the percentages that the owners hold in the title. The basic formula for
the assessment of freehold mineral tax is: revenue less allocable costs equals net revenue divided by
wellhead production equals the value based upon unit of production. If payors do not wish to file individual
unit values, a default price is supplied by the Crown. On average, the tax levied is 4 percent of revenues
reported from fee simple mineral title properties.
Any changes to the royalty regime in Alberta may have a material effect on Surge. See “Risk Factors -
Royalty Regimes.”
Saskatchewan
In Saskatchewan, the amount payable as a Crown royalty or a freehold production tax in respect of oil
depends on the type and vintage of oil, the quantity of oil produced in a month, the value of the oil
produced and specified adjustment factors determined monthly by the provincial government.
For Crown royalty and freehold production tax purposes, conventional oil is divided into “types”, being
“heavy oil”, “southwest designated oil” or “non-heavy oil other than southwest designated oil”. The
conventional royalty and production tax classifications (“fourth tier oil”, “third tier oil”, “new oil” and “old
oil”) depend on the finished drilling date of a well and are applied to each of the three crude oil types
slightly differently.
Heavy oil is classified as third tier oil (produced from a vertical well having a finished drilling date on or
after January 1, 1994 and before October 1, 2002 or incremental oil from new or expanded water flood
projects with a commencement date on or after January 1, 1994 and before October 1, 2002), fourth tier
oil (having a finished drilling date on or after October 1, 2002 or incremental oil from new or expanded
water flood projects with a commencement date on or after October 1, 2002) or new oil (conventional oil
that is not classified as “third tier oil” or “fourth tier oil”). Southwest designated oil means oil produced
within the southwest area that is produced from an oil or gas well with a finished drilling date on or after
February 9, 1998 or incremental waterflood oil that commenced operation after February 9, 1998.
Southwest designated oil uses the same definition of fourth tier oil but third tier oil is defined as
conventional oil produced from a vertical well having a finished drilling date on or after February 9, 1998
and before October 1, 2002 or incremental oil from new or expanded water flood projects with a
commencement date on or after February 9, 1998 and before October 1, 2002, and new oil is defined as
conventional oil produced from a horizontal well having a finished drilling date on or after February 9,
1998 and before October 1, 2002. For non-heavy oil other than southwest designated oil, the same
classification as heavy oil is used but new oil is defined as conventional oil produced from a vertical well
completed after 1973 and having a finished drilling date prior to 1994, conventional oil produced from a
horizontal well having a finished drilling date on or after April 1, 1991 and before October 1, 2002, or
incremental oil from new or expanded water flood projects with a commencement date on or after
January 1, 1974 and before 1994 whereas old oil is defined as conventional oil not classified as third or
fourth tier oil or new oil.
Production tax rates for freehold production are determined by first determining the Crown royalty rate
and then subtracting the “Production Tax Factor” (“PTF”) applicable to that classification of oil. Currently
the PTF is 6.9 for “old oil”, 10.0 for freehold “new oil” and freehold “third tier oil” and 12.5 for freehold
“fourth tier oil”. The minimum rate for freehold production tax is zero.
Base prices are used to establish lower limits in the price-sensitive royalty structure for conventional oil
and apply at various reference well production rates (m3 per month) for old oil, new oil, third tier oil and
fourth tier oil. Where average wellhead prices are below the established base prices of $100 per m3 for
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third and fourth tier oil and $50 per m3 for new oil and old oil, base royalty rates are applied. Base royalty
rates are 5 percent for all fourth tier oil, 10 percent for heavy oil that is third tier oil or new oil, 12.5 percent
for southwest designated oil that is third tier oil or new oil, 15 percent for non-heavy oil other than
southwest designated oil that is third tier or new oil, and 20 percent for old oil. Where average wellhead
prices are above base prices, marginal royalty rates are applied to the proportion of production that is
above the base oil price. Marginal royalty rates are 30 percent for all fourth tier oil, 25 percent for heavy
oil that is third tier oil or new oil, 35 percent for southwest designated oil that is third tier oil or new oil, 35
percent for non-heavy oil other than southwest designated oil that is third tier or new oil, and 45 percent
for old oil.
The amount payable as a Crown royalty or a freehold production tax in respect of natural gas production
is determined by a sliding scale based on the monthly provincial average gas price published by the
Saskatchewan government (effective February 1, 2012), the quantity produced in a given month, the type
of natural gas, and the classification of the natural gas. Like conventional oil, natural gas may be
classified as “non-associated gas” (gas produced from gas wells) or “associated gas” (gas produced from
oil wells) and royalty rates are determined according to the finished drilling date of the respective well.
Non-associated gas is classified as new gas (having a finished drilling date before February 9, 1998 with
a first production date on or after October 1, 1976), third tier gas (having a finished drilling date on or after
February 9, 1998 and before October 1, 2002), fourth tier gas (having a finished drilling date on or after
October 1, 2002) and old gas (not classified as either third tier, fourth tier or new gas). A similar
classification is used for associated gas except that the classification of old gas is not used, the definition
of fourth tier gas also includes production from oil wells with a finished drilling date prior to October 1,
2002, where the individual oil well has a gas-oil production ratio in any month of at least 3,500 m3 of gas
for every m3 of oil, and new gas is defined as oil produced from a well with a finished drilling date before
February 9, 1998 that received special approval, prior to October 1, 2002, to produce oil and gas
concurrently without gas-oil ratio penalties.
On December 9, 2010, the Government of Saskatchewan enacted the Freehold Oil and Gas Production
Tax Act, 2010 with the intention to facilitate the efficient payment of freehold production taxes by industry.
Two new regulations with respect to this legislation are: (i) The Freehold Oil and Gas Production Tax
Regulations, 2012 which sets out the terms and conditions under which the taxes are calculated and paid;
and (ii) The Recovered Crude Oil Tax Regulations, 2012 which sets out the terms and conditions under
which taxes on recovered crude oil that was delivered from a crude oil recovery facility on or after March
1, 2012 are to be calculated and paid.
Base royalty rates are 5 percent for all fourth tier gas, 15 percent for third tier or new gas, and 20 percent
for old gas. Where average well-head prices are above base prices, marginal royalty rates are applied to
the proportion of production that is above the base gas price. Marginal royalty rates are 30 percent for all
fourth tier gas, 35 percent for third tier and new gas, and 45 percent for old gas. The current regulatory
scheme provides for certain differences with respect to the administration of fourth tier gas which is
associated gas.
The Government of Saskatchewan currently provides a number of targeted incentive programs. These
include both royalty reduction and incentive volume programs, including the following:
• Royalty/Tax Incentive Volumes for Vertical Oil Wells Drilled on or after October 1, 2002 providing
reduced Crown royalty (a Crown royalty rate of the lesser of “fourth tier oil” Crown royalty rate and
2.5 percent) and freehold tax rates (a freehold production tax rate of 0 percent) on incentive
volumes of 8,000 m3 for deep development vertical oil wells, 4,000 m3 for non-deep exploratory
vertical oil wells and 16,000 m3 for deep exploratory vertical oil wells (more than 1,700 metres or
within certain formations) and after the incentive volume is produced, the oil produced will be
subject to the “fourth tier” royalty tax rate;
• Royalty/Tax Incentive Volumes for Exploratory Gas Wells Drilled on or after October 1, 2002
providing reduced Crown royalty (a Crown royalty rate of the lesser of “fourth tier oil” Crown
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royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of 0 percent)
on incentive volumes of 25,000,000 m3 for qualifying exploratory gas wells;
• Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002
providing reduced Crown royalty (a Crown royalty rate of the lesser of “fourth tier oil” Crown
royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of 0 percent)
on incentive volumes of 6,000 m3 for non-deep horizontal oil wells and 16,000 m3 for deep
horizontal oil wells (more than 1,700 metres total vertical depth or within certain formations) and
after the incentive volume is produced, the oil produced will be subject to the “fourth tier” royalty
tax rate;
• Royalty/Tax Incentive Volumes for Horizontal Gas Wells drilled on or after June 1, 2010 and
before April 1, 2013 providing for a classification of the well as a qualifying exploratory gas well
and resulting in a reduced Crown royalty (a Crown royalty rate of the lesser of “fourth tier oil”
Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of 0
percent) on incentive volumes of 25,000,000 m3 for horizontal gas wells and after the incentive
volume is produced, the gas produced will be subject to the “fourth tier” royalty tax rate;
• Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects
Implemented on or after October 1, 2002 whereby incremental production from approved water
flood projects is treated as fourth tier oil for the purposes of Crown royalty and freehold tax
calculations;
• Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects)
Commencing prior to April 1, 2005 providing lower Crown royalty and freehold tax determinations
based in part on the profitability of EOR projects during and subsequent to the payout of the EOR
operations;
• Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects)
Commencing on or after April 1, 2005 providing a Crown royalty of 1 percent of gross revenues
on EOR projects pre-payout and 20 percent of EOR operating income post-payout and a freehold
production tax of 0 percent pre-payout and 8 percent post-payout on operating income from EOR
projects; and
• Royalty/Tax Regime for High Water-Cut Oil Wells designed to extend the producing lives and
improve the recovery rates of high water-cut oil wells and granting “third tier oil” royalty/tax rates
with a Saskatchewan Resource Credit of 2.5 percent for oil produced prior to April 2013 and 2.25
percent for oil produced on or after April 1, 2013 to incremental high water-cut oil production
resulting from qualifying investments made to rejuvenate eligible oil wells and/or associated
facilities.
On June 22, 2011, the Government of Saskatchewan released the Upstream Petroleum Industry
Associated Gas Conservation Standards, which are designed to reduce emissions resulting from the
flaring and venting of associated gas (the “Associated Natural Gas Standards”). The Associated
Natural Gas Standards were jointly developed with industry and the implementation of such standards
commenced on July 1, 2012 for new wells and facilities licensed on or after such date. The new
standards apply to all existing licensed wells and facilities as of July 1, 2015.
Effective April 1, 2014, the Saskatchewan Ministry of the Economy streamlined fees related to licenses
and applications in the oil and gas sector by eliminating 10 different licensing fees, which resulted in an
aggregate of 20,000 fee transactions per year, and replacing them with a single annual levy based on a
company’s production and number of wells. While the fees have been streamlined, approvals to conduct
the relevant activities are still required. These changes to the fee structure are part of ongoing work by
the Government of Saskatchewan to streamline the licensing, regulation and monitoring processes in the
oil and gas sector.
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Climate Change Regulation
Federal
Canada is a signatory to the United Nations Framework Convention on Climate Change (the “UNFCCC”),
which was entered into in order work towards stabilizing atmospheric concentrations of greenhouse gas
(“GHG”) emissions at a level to prevent “dangerous anthropogenic interference with the climate system”.
The UNFCCC came into force on March 21, 1994. Subsequent international negotiations led to the Kyoto
Protocol, an international treaty which extends the UNFCCC and commits its signatories to reduce GHG
emissions. The Kyoto Protocol was adopted in December 1997 and came into force on February 16,
2005. Canada withdrew from the Kyoto Protocol effective December 2012. On December 12, 2015, the
UNFCCC adopted the Paris Agreement, which Canada ratified on October 5, 2016. Under the Paris
Agreement, countries have also committed to an ambitious goal of holding the increase in global average
temperature to well below 2°C above pre-industrial levels, while they pursue efforts to limit the
temperature increase to 1.5°C above pre-industrial levels. In 2018, members of the Paris Agreement
launched the Talanoa dialogue in order to assess the members’ collective efforts and progress with
respect to the long term goal to peak global GHG emissions, and subsequently achieve net zero
emissions.
In May 2015, Canada submitted its Intended Nationally Determined Contribution (“INDC”) to the UNFCCC
Secretariat, pledging a 30 percent reduction from 2005 levels – approximately 523 Mt – by 2030. In
addition, provincial/territorial and federal leaders met and agreed that they would work together to build a
national climate change plan. At a follow-up meeting of the First Ministers and Prime Minister on March 3,
2016, the parties agreed under the Vancouver Declaration on Clean Growth and Climate Change to
launch a process to develop the Pan-Canadian Framework on Clean Growth and Climate Change (the
“Framework”), which was released on December 9, 2016 at the First Ministers meeting. Saskatchewan
was the only province that decided not to adopt the Framework.
Prior to the release of the Framework, the federal government announced in October 2016 that it will set
a minimum price on carbon starting at $10 per tonne of CO2e in 2018, which will increase by $10 per year
until it reaches $50 per tonne of CO2e by 2022. This approach will be reviewed in 2022 to confirm the
path forward, including continued increases in stringency. Under the federal plan, each province and
territory will be required to implement carbon pricing in its jurisdiction by 2018, whether in the form of a
carbon tax or a cap-and-trade system. If the carbon price in a jurisdiction does not meet the federal
minimum price, the federal government will step in and impose a carbon price that makes up the
difference and return the revenue to the province or territory. In addition, provincial and territorial goals for
reducing emissions must be at least as stringent as federal targets. Currently, Canada’s four biggest
provinces representing more than 80 percent of Canada’s population (Ontario, Québec, Alberta and
British Columbia) have carbon pricing in place that meets the federal benchmark.
In May 2017, Environment and Climate Change Canada (“ECCC”) released its Technical Paper on the
Federal Carbon Pricing Backstop, which was followed by the Guidance on the Pan-Canadian Carbon
Pollution Pricing Benchmark in August 2017. In December 2017, Supplemental Benchmark Guidance
was issued and federal Environment Minister Catherine McKenna and Finance Minister Bill Morneau
announced a deadline of September 1, 2018 for each province to outline how it is implementing a carbon
pricing system that meets the federal standard (the federal government has requested that provinces and
territories that choose the federal backstop, in whole or in part, confirm this by March 30, 2018). The
federal government will then determine whether the planned systems are on track to meet the standard,
or whether the federal approach should be applied in that jurisdiction. On January 15, 2018, ECCC
released draft legislative proposals for public comment relating to the proposed Greenhouse Gas
Pollution Pricing Act and the proposed regulatory framework for the output-based pricing system (which is
designed to minimize competitiveness risks for emissions-intensive, trade-exposed industrial facilities).
The comment periods for the federal carbon pricing backstop legislation and the regulatory framework
end on February 12, 2018 and April 9, 2018, respectively.
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On May 27, 2017, the federal government published draft regulations to reduce emissions of methane
from the crude oil and natural gas sector. The proposed 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, by introducing new control measures. Among other things, the
proposed regulations limit how much methane upstream oil and 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.
In March 2016, a Joint Statement on Climate, Energy, and Arctic Leadership was issued. This joint
statement sets out specific commitments on energy development, environmental protection, and Arctic
leadership. In particular, Canada and the US have made commitments to reduce methane emissions by
40-45 percent below 2012 levels by 2025 from the oil and gas sector, finalize and implement the second
phase of an aligned GHG emission standard for post-2018 model year on-road heavy duty vehicles,
phase out fossil fuel subsidies, accelerate clean energy development and foster sustainable energy
development.
In December 2017, ECCC published its updated requirements and step-by-step reporting instructions in
advance of the 2017 reporting period under the federal Greenhouse Gas Reporting Program (“GHGRP”).
The Notice with respect to reporting of greenhouse gases for 2017, which was published on
December 30, 2017 in Part I of the Canada Gazette, outlines the 2017 reporting requirements for GHG-
emitting facilities. In December 2017, ECCC published its updated requirements and step-by-step
reporting instructions in advance of the 2017 reporting period under the GHGRP. Stakeholders should
note that for the 2017 reporting year under the GHGRP, the reporting threshold has been lowered from
50,000 tonnes to 10,000 tonnes of CO2e. All facilities that emitted the equivalent of 10,000 tonnes of
CO2e in 2017 will be required to submit a report by June 1, 2018.
In November 2016, the federal government announced that it would commence development of a
performance-based clean fuel standard (“CFS”) that would incent the use of a broad range of low carbon
fuels, energy sources and technologies. The objective of the CFS is to achieve 30 Mt of annual
reductions in GHG emissions by 2030, as part of efforts to achieve Canada’s commitments under the
Paris Agreement. On December 13, 2017, ECCC published a regulatory framework on the CFS, which
outlines the key design elements for the CFS regulation, including its scope, regulated parties, carbon
intensity approach, timing, and potential compliance options such as credit trading. Draft CFS regulations
are expected to be published in late 2018.
Surge will continue to monitor the policies of the Government of Canada and any resulting legislation with
respect to GHG emissions. The US Environmental Protection Agency (“EPA”) is proceeding to regulate
GHGs under the Clean Air Act. This EPA action is subject to legal and political challenges, the outcome
of which cannot be predicted. The ultimate form of Canadian regulation is anticipated to be strongly
influenced by the regulatory decisions made within the United States. Various states have enacted or are
evaluating low carbon fuel standards, which may affect access to market for crude oils with higher
emissions intensity.
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Alberta
On July 1, 2007, the Specified Gas Emitters Regulation (“SGER”) came into force under Alberta’s Climate
Change and Emissions Management Amendment Act requiring Alberta facilities which emit more than
100,000 tonnes of GHGs annually (“Regulated Emitters”) to reduce their GHG emissions intensity by 12
percent (from average 2003-2005 levels). On June 25, 2015, the Government of Alberta renewed the
SGER for a period of two years with significant amendments while Alberta’s newly formed Climate
Advisory Panel conducted a comprehensive review of the province’s climate change policy.
Alberta’s Climate Leadership Plan was introduced in November 2015 with the following policy objectives:
(i) putting a price on GHG emissions; (ii) phasing out coal-generated electricity by 2030; (iii) having 30
percent of electricity be generated from renewable sources by 2030; (iv) capping oil sands emissions to
100 Mt per year; and (v)reducing methane emissions by 45 percent by 2025.
Carbon pricing was identified under the Climate Leadership Plan as a key policy tool for reducing GHG
emissions. On January 1, 2017, a carbon levy of $20 per tonne of CO2e was implemented and applies to
all heating and transportation fuels. The carbon levy increased to $30 per tonne on January 1, 2018.
On January 1, 2018, the Carbon Competitiveness Incentive Regulation (“CCI Regulation”) replaced
the Specified Gas Emitters Regulation. Under the CCI Regulation, facilities are allowed to emit a certain
amount of GHG, free of charge from the carbon levy. This approach is designed to protect industries from
competitiveness impacts that could shift production to other jurisdictions. The CCI Regulation applies to
facilities that emitted 100,000 tonnes or more of GHG in 2003, or a subsequent year. A facility with less
than 100,000 tonnes of GHG may be eligible to opt-in to the CCI Regulation if it competes against a
facility regulated under the CCI or has more than 50,000 tonnes of annual emissions, high emissions-
intensity and trade-exposure (by opting in, facilities become exempt from the application of the carbon
levy for fuels whose emissions are included in their site reporting). Under the updated system, a facility
will receive performance credits if its GHG emissions are less than the amount freely permitted. If its
emissions are above the amount freely permitted, they will be required take one or more of the following
actions to bring the facility into compliance:
(cid:2) make improvements at their facility to reduce emissions intensity;
(cid:2) use emission performance credits generated at facilities that achieve more than the
required reductions;
(cid:2) purchase Alberta-based carbon offset credits; or
(cid:2)
contribute to Alberta's Climate Change and Emissions Management Fund.
Emissions from the oil sands sector (which account for approximately one-quarter of Alberta’s annual
emissions) have been capped at 100 Mt per year. This cap has been legislated in the Oil Sands
Emissions Limit Act (Bill 25), which was introduced in November 2016. The legislation contemplates
certain exceptions in respect of cogeneration emissions, upgrading emissions, and potential discretionary
exemptions by regulation (likely to accommodate new technological developments). Bill 25 came into
force on December 14, 2016.
In January 2018, the Alberta government also announced that it is adopting ECCC’s greenhouse gas
reporting requirements for the 2017 reporting period, meaning that facilities emitting 10,000 tonnes of
CO2e or more must submit a specified gas report to Alberta Climate Change Office via ECCC’s SWIM
reporting system (the reporting threshold for previous years is 50,000 tonnes of CO2e). Facilities must
report their 2017 greenhouse gas emissions to ECCC’s SWIM system by June 1, 2018.
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Saskatchewan
In October 2016, Saskatchewan released its Climate Change White Paper, which outlined the principles
of the province's approach to climate change, including a focus on both mitigation and adaptation
responses to climate change. Following the release of the White Paper, the government worked on
developing its comprehensive climate change strategy, which was released in December 2017: Prairie
Resilience: A Made-in-Saskatchewan Climate Change Strategy (the “Strategy”). The Strategy focuses on
the principles of readiness and climate resilience, curbing GHG emissions, and preparing for changing
conditions such as extreme weather, drought or wildfire. Saskatchewan has decided not to sign on to the
Pan-Canadian Framework on Clean Growth and Climate Change or to adopt a carbon pricing
mechanism, meaning that it will be out of compliance with federal requirements. The Strategy proposes
actions in key areas, including (i) natural systems; (ii) physical infrastructure; (iii) economic sustainability;
(iv) community preparedness; and (v) measuring, monitoring and reporting. Although no specific emission
reduction targets are set out in the Strategy, the Saskatchewan government has indicated that it will
support Canada’s efforts to meet national commitments under the Paris Agreement. Prior to the release
of the Strategy, Saskatchewan relied on the GoGreen Saskatchewan initiative to encourage the reduction
of GHG emissions and to educate the public about climate change. Between 2008 and 2015, the
Saskatchewan government estimates that it invested $60 million in GoGreen funding through
public/private partnerships.
Saskatchewan has also identified technology as a key driver of emission reductions, including carbon
capture use and storage as well as renewable energy. In 2015, SaskPower set a target of doubling its
percentage of electricity capacity from renewable energy sources, i.e. to have 50 percent of the
province’s power sourced from renewables by 2030.
As part of the Strategy, Saskatchewan will develop annual GHG reporting regulations for facilities that
emit more than 25,000 tonnes of CO2e annually (with a voluntary opt-in for emitters over 10,000 tonnes of
CO2e annually).
Land Tenure
Crude oil and natural gas located in the Western Canadian provinces is owned both by the respective
provincial governments and by private individuals. Provincial governments grant rights to explore for and
produce oil and natural gas pursuant to leases, licenses and permits for varying periods and on
conditions set forth in provincial legislation, including requirements to perform specific work or make
payments. Where oil and natural gas is privately owned, rights to explore for and produce such oil and
natural gas are granted by lease on such terms and conditions as may be negotiated.
The respective provincial governments predominantly own the rights to crude oil and natural gas located
in the western provinces, with the exception of Manitoba where private ownership accounts for
approximately 80 percent of the crude oil and natural gas rights in the southwestern portion of the
province. 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.
Each of the provinces of Alberta and Saskatchewan 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.
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 license. Holders of leases or licences that have been continued
indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights,
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which will be implemented three years from the date of the notice. In 2013, Alberta Energy placed an
indefinite hold on serving shallow rights reversion notices for leases and licences that were granted prior
to January 1, 2009. Alberta Energy stated that it will provide the industry with notice if, in the future, a
decision is made to serve shallow rights reversion notices.
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 from time to
time. Such legislation provides for restrictions and prohibitions on the release or emitting 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 for the satisfactory
abandonment and reclamation of well and facility sites and provides form among other things, restrictions
and prohibitions on spills, releases, discharges, or emissions of various substances produced in
association with oil and gas operations, habitat protection and minimum setbacks of oil and gas activities
from fresh water bodies. 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.
Certain environmental protection legislation may subject Surge to statutory strict liability in the event of an
accidental spill or discharge from a licensed facility, meaning that fault need not be established by
claimants affected by such a spill or discharge. Further, as Canadian environmental legislation evolves,
the use of administrative penalties by the imposition of fines for the commission of environmental
offences on an absolute liability basis has grown.
Environmental legislation is evolving in a manner that has and is expected to continue to result in stricter
standards and enforcement, larger fines, liabilities and sanctions, and potentially increased capital
expenditures and operating costs. To mitigate potential environmental liabilities, Surge in addition to
implementing policies and procedures designed to prevent an accidental spill or discharge, maintains
insurance at industry standards.
Federal
Canadian environmental regulation is the responsibility of the federal government and provincial
governments. Where there is a direct conflict between federal and provincial environmental legislation in
relation to the same matter, the federal law will prevail, however, such conflicts are uncommon. The
federal government has primary jurisdiction over federal works, undertakings and federally regulated
industries such as railways, aviation and interprovincial transport. The Canadian Environmental
Protection Act and the Canadian Environmental Assessment Act, provide the foundation for the federal
government to protect the environment and cooperate with provinces to do the same.
On February 8, 2018, the Government of Canada introduced draft legislation to overhaul the existing
environmental assessment process and replace the NEB with the Canadian Energy Regulator ("CER").
Pursuant to the draft legislation, the Impact Assessment Agency of Canada (the "Agency") would replace
the Canadian Environmental Assessment Agency. Additional categories of projects may be included
within new impact assessment process, such as largescale wind power facilities and in-situ oilsands
facilities. The revamped approval process for applicable major developments will have specific legislated
timelines at each stage of the formal impact assessment process. The Agency's process would focus on:
(i) early engagement by proponents to engage the Agency and all stakeholders, such as the public and
indigenous groups, prior to the formal impact assessment process; (ii) potentially increased public
participation where the project undergoes a panel review; (iii) providing analysis of the potential impacts
and effects of a project without making recommendations, to support a public-interest approach to
decision-making, with cost-benefit determinations and approvals made by the Minister of Environment
and Climate Change or the cabinet of the federal government; (iv) analyzing further specified factors for
projects such as alternatives to the project and social and indigenous issues in addition to health,
environmental and economic impacts; and (v) overseeing an expanded follow-up, monitoring and
enforcement process with increased involvement of indigenous peoples and communities. Many of the
CER’s activities would be similar to the NEB, but with a different structure and the notable exception that
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the CER would no longer have primary responsibility in the consideration of the new major projects,
instead focusing on the lifecycle regulation (e.g. overseeing construction, tolls and tariffs, operations and
eventual winding down) of approved projects, while providing for expanded participation by communities
and indigenous peoples. It is unclear when the new regulatory scheme will come into force or whether
any amendments will be made prior to coming into force. Until then, the federal government's interim
principles released on January 27, 2016 will continue to guide decision-making authorities for projects
currently undergoing environmental assessment. The effects of the proposed regulatory scheme remains
unclear.
On May 12, 2017, the federal government introduced the Oil Tanker Moratorium Act in Parliament. This
legislation is aimed at providing coastal protection in northern British Columbia by prohibiting crude oil
tankers carrying more than 12,500 metric tonnes of crude oil or persistent crude oil products from
stopping, loading, or unloading crude oil in that area. Parliament is still considering the bill, which passed
second reading on October 4, 2017. If implemented, the legislation may prevent the building of pipelines
to, and export terminals located on, the portion of the British Columbia coast subject to the moratorium
and, as a result, negatively affect the ability of producers to access global markets.
Alberta
Environmental legislation in the Province of Alberta is, for the most part, set out in the Environmental
Protection and Enhancement Act (“EPEA”), the Water Act and the Oil and Gas Conservation Act
(“ABOGCA”). EPEA, the Water Act and the ABOGCA impose strict environmental standards with respect
to releases of effluents and emissions, require stringent compliance, reporting and monitoring obligations,
and impose significant penalties for non-compliance.
The regulatory landscape in Alberta has undergone a transformation from multiple regulatory bodies to a
single regulator for upstream oil and gas, oil sands and coal development activity. On June 17, 2013, the
Alberta Energy Regulator (the “AER”) assumed the functions and responsibilities of the former Energy
Resources Conservation Board, including those found under the ABOGCA. On November 30, 2013, the
AER assumed the energy related functions and responsibilities of Alberta Environment and Parks (“AEP”)
in respect of the disposition and management of public lands under the Public Lands Act. On March 29,
2014, the AER assumed the energy related functions and responsibilities of AEP in the areas of
environment and water under EPEA and the Water Act, respectively. The AER’s responsibilities exclude
the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as Alberta
Energy’s responsibility for mineral tenure. The objective behind the transformation to a single regulator is
the creation of an enhanced regulatory regime that is efficient, attractive to business and investors, and
effective in supporting public safety, environmental management and resource conservation while
respecting the rights of landowners.
In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta,
the Alberta Land Use Framework (the “ALUF”). The ALUF 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 Alberta Land Stewardship Act (the “ALSA”) provides the legislative authority for the Government of
Alberta to implement the policies contained in the ALUF. Regional plans established under the ALSA are
deemed to be legislative instruments equivalent to regulations and will be binding on the Government of
Alberta and provincial regulators, including those governing the oil and gas industry. In the event of a
conflict or inconsistency between a regional plan and another regulation, regulatory instrument or
statutory consent, the regional plan will prevail. Further, the ALSA requires local governments, provincial
departments, agencies and administrative bodies or tribunals to review their regulatory instruments and
make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also
contemplates the amendment or extinguishment of previously issued statutory consents such as
regulatory permits, licenses, registrations, approvals and authorizations for the purpose of achieving or
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maintaining an objective or policy resulting from the implementation of a regional plan. Among the
measures to support the goals of the regional plans contained in the ALSA are conservation easements,
which can be granted for the protection, conservation and enhancement of land, and conservation
directives, which are explicit declarations contained in a regional plan to set aside specified lands in order
to protect, conserve, manage and enhance the environment.
On August 22, 2012, the Government of Alberta approved the Lower Athabasca Regional Plan (“LARP”)
which came into force on September 1, 2012. The LARP is the first of seven regional plans developed
under the ALUF. LARP covers a region in the northeastern corner of Alberta that is approximately 93,212
square kilometres in size. The region includes a substantial portion of the Athabasca oilsands area, which
contains approximately 82 percent of the province’s oilsands resources and much of the Cold Lake
oilsands area. LARP establishes six new conservation areas and nine new provincial recreation areas. In
conservation and provincial recreation areas, conventional oil and gas companies with pre-existing tenure
may continue to operate. Any new petroleum and gas tenure issued in conservation and provincial
recreation areas will include a restriction that prohibits surface access.
The South Saskatchewan Regional Plan (“SSRP”) was approved by the Government of Alberta on July
23, 2014 and became effective on September 1, 2014. The SSRP is the second regional plan developed
under the ALUF and covers approximately 83,764 square kilometres and includes 44 percent of the
province’s population.
The SSRP creates four new and four expanded conservation areas, and two new and six expanded
provincial parks and recreational areas. Similar to LARP, the SSRP will honour existing petroleum and
natural gas tenure in conservation and provincial recreational areas. However, oil and gas companies
must nonetheless minimize impacts of activities on the natural landscape, historic resources, wildlife, fish
and vegetation when exploring, developing and extracting the resources. Any new petroleum and natural
gas tenures sold in conservation areas, provincial parks, and recreational areas will prohibit surface
access. Freehold mineral rights will not be subject to this restriction. With the implementation of the new
Alberta regulatory structure under the AER, AEP will remain responsible for development and
implementation of regional plans. However, the AER will take on some responsibility for implementing
regional plans in respect of energy related activities.
Saskatchewan
Saskatchewan’s Ministry of the Economy and the Oil and Gas Conservation Board collectively regulate oil
and gas activities in the province, which is primarily governed by the Natural Resources Act and The Oil
and Gas Conservation Act (“SKOGCA”).
The Environmental Management and Protection Act (“EMPA”) regulates the protection of the environment
in Saskatchewan, including among others the designation of environmentally impacted sites, issuance of
environmental protection orders, and obligations to report releases of substances. Most importantly, the
EMPA prohibits the discharge of substances causing adverse effects to the environment, and assigns
responsibility for such adverse effects to a broad category of “persons responsible.” This includes the
person who caused or contributed to the discharge (i.e. fugitive release of sour gas or flaring in excess of
the permitted levels), had possession or control of the substance, as well as every owner and occupier of
the land, including subsequent owners and occupiers and any person transporting the substance.
In May 2011, Saskatchewan passed changes to SKOGCA. Although the associated Bill received Royal
Assent on May 18, 2011, it was not proclaimed into force until April 1, 2012, in conjunction with the
release of The Oil and Gas Conservation Regulations, 2012 (“OGCR”) and The Petroleum Registry and
Electronic Documents Regulations (“Registry Regulations”). The aim of the amendments to the
SKOGCA, and the associated regulations, is to provide resource companies investing in Saskatchewan’s
energy and resource industries with the best support services and business and regulatory systems
available. With the enactment of the Registry Regulations and the OGCR, Saskatchewan has
implemented a number of operational aspects, including the increased demand for record-keeping,
increased testing requirements for injection wells and increased investigation and enforcement powers,
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and procedural aspects, including those related to Saskatchewan’s participation as partner in the
Petroleum Registry of Alberta.
On June 22, 2011, the Government of Saskatchewan released the Upstream Petroleum Industry
Associated Gas Conservation Standards, which are designed to reduce emissions resulting from the
flaring and venting of associated gas (the "Associated Natural Gas Standards"). The Associated
Natural Gas Standards were jointly developed with industry and the implementation of such standards
commenced on July 1, 2012 for new wells and facilities licensed on or after such date. The new
standards will apply to existing licensed wells and facilities on July 1, 2015.
Liability Management Rating Programs
Alberta
In Alberta, the AER administers the Licensee Liability Rating Program (the “AB LLR Program”) as part of
the Liability Management Rating Assessment Process. The AB LLR Program is a liability management
program governing most conventional upstream oil and gas wells, facilities and pipelines. The ABOGCA
establishes an orphan fund (the “Orphan Fund”) to pay the costs to suspend, abandon, remediate and
reclaim a well, facility or pipeline included in the AB LLR Program if a licensee or working interest
participant (“WIP”) becomes defunct. The Orphan Fund is funded by licensees in the AB LLR Program
through a levy administered by the AER. The AB LLR Program is designed to minimize the risk to the
Orphan Fund posed by unfunded liability of licensees and prevent the taxpayers of Alberta from incurring
costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines. In short, the AB LLR
Program requires a licensee whose deemed liabilities exceed its deemed assets (and therefore the
licensee has a resulting LLR of less than 1.0) to provide the AER with a security deposit. In certain
circumstances, for example during the transfer of AER licenses between parties, the AER will require that
the transferee must achieve an LLR of 2.0 or higher immediately following the proposed transfer of the
applicable licenses. The ratio of deemed liabilities to deemed assets is assessed once each month and
upon the submission of a license transfer application, and failure to post the required security deposit may
result in the initiation of enforcement actions by the AER.
On June 20, 2016, the AER issued Bulletin 2016-16, Licensee Eligibility—Alberta Energy Regulator
Measures to Limit Environmental Impacts Pending Regulatory Changes to Address the Redwater
Decision ("Bulletin 16") in an urgent response to a decision from the Alberta Court of Queen's Bench,
which was affirmed by a majority at the Alberta Court of Appeal. In Redwater Energy Corporation (Re),
2016 ABQB 278 ("Redwater"), Chief Justice Wittman found that there was an operational conflict
between the abandonment and reclamation provisions of the Oil and Gas Conservation Act (Alberta) and
the Bankruptcy and Insolvency Act ("BIA"), and that receivers and trustees have the right to renounce
assets within
legislated authority
unenforceable 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 insolvent. Effectively, this means that
abandonment costs will be borne by the industry-funded Orphan Well Fund or the province in these
instances because any resources of the insolvent licensee will first be used to satisfy secured creditors
under the BIA. The decision is currently under appeal to the Supreme Court of Canada, with final decision
expected in 2018.
insolvency proceedings. Such a conflict renders
the AER's
The AER issued several bulletins in response to Redwater. Bulletin 16 provides interim rules to govern
while the case is appealed and while the Government of Alberta can develop appropriate regulatory
measures to adequately address environmental liabilities. The AER’s Directive 67 was amended and now
requires extensive corporate governance and shareholder information, with a focus on any previous
insolvency proceedings in order to acquire or transfer licenses needed to operate wells and facilities. The
AER will consider and process all applications for licence eligibility under Directive 067: Applying for
Approval to Hold EUB Licences as non-routine and may exercise its discretion to refuse an application or
impose terms and conditions on a licensee eligibility approval if appropriate in the circumstances. As a
condition of transferring existing AER licences, approvals, and permits, the AER will require all
transferees to demonstrate that they have a liability management rating ("LMR"), being the ratio of a
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licensee's assets to liabilities, of 2.0 or higher immediately following the transfer. The AER may implement
additional changes in response to the final Redwater decision.
The AER 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. 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 percent 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 list of current wells subject to the IWCP is
available on the AER's Digital Data Submission system. The AER has announced that from April 1, 2015
to April 1, 2016, the number of noncompliant wells subject to the IWCP fell from 25,792 to 17,470, with 76
percent of licensees operating in the province having met their annual quota. The IWCP completed its
second year on March 31, 2017. Overall, the AER has announced that licensees brought 19 percent of
non-compliant wells in the IWCP into compliance with AER requirements in the second year of the IWCP.
Saskatchewan
In Saskatchewan, the Ministry of Economy implements the Licensee Liability Rating Program (the “SK
LLR Program”). The SK LLR Program is designed to assess and manage the financial risk that a
licensee’s well and facility abandonment and reclamation liabilities pose to an orphan fund (the “Oil and
Gas Orphan Fund”). The Oil and Gas Orphan Fund is responsible for carrying out the abandonment and
reclamation of wells and facilities contained within the SK LLR Program when a licensee or WIP is
defunct or missing. The SK LLR Program requires a licensee whose deemed liabilities exceed its
deemed assets to post a security deposit. The ratio of deemed liabilities to deemed assets is assessed
each month for all licensees of oil, gas and service wells and upstream oil and gas facilities. On August
19, 2016, the Ministry of the Economy released a notice to all operators that it would follow the AER's
interim rules by processing all licence transfer applications as non-routine until further notice.
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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.
Operational Risks
Oil and natural gas exploration operations are subject to all the risks and hazards typically associated
with such operations, including hazards such as fire, explosion, blowouts, cratering and oil spills, each of
which could result in substantial damage to oil and natural gas wells, producing facilities, other property
and the environment or in personal injury. In accordance with industry practice, Surge is not fully insured
against all of these risks, nor are all such risks insurable. Although Surge maintains liability insurance in
an amount which it considers adequate, the nature of these risks is such that liabilities could exceed
policy limits, in which event Surge could incur significant costs that could have a materially adverse effect
upon its financial condition. Oil and natural gas production operations are also subject to all the risks
typically associated with such operations, including premature decline of reservoirs and the invasion of
water into producing formations.
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 Surge and may delay
exploration and development activities.
Oil and natural gas exploration and development activities are dependent on access to areas where
operations are to be conducted. Seasonal weather variations, including freeze-up and break-up, affect
access in certain circumstances. Unexpected adverse weather conditions, such as flooding or prolonged
break-up, can have a significant negative impact on capital expenditures, operations and costs.
To the extent Surge is not the operator of its oil and natural gas properties, it is dependent on such
operators for the timing of activities related to such properties and is largely unable to direct or control the
activities of the operators. Payments from production generally flow through the operator and there is a
risk of delay and additional expense in receiving such revenues if the operator becomes insolvent.
Although Surge intends to operate the majority of its properties, there is no guarantee that it will remain
operator of such properties or that Surge will operate other properties it may acquire in the future.
In addition, the success of Surge will be largely dependent upon the performance of its management and
key employees. Surge does not have any key man insurance policies and, therefore, there is a risk that
the death or departure of any member of management or any key employee could have a material
adverse effect on Surge.
Surge’s ability to market oil and natural gas from its wells also depends upon numerous other factors
beyond its control, including, among other things, the availability of natural gas processing and storage
capacity, the availability of pipeline capacity, the price of oilfield services and the effects of inclement
weather. Because of these factors, Surge may be unable to market some or all of the oil and natural gas
it produces or to obtain favourable prices for the oil and natural gas it produces.
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Volatility of Oil and Natural Gas Prices and Markets
Surge’s financial performance and condition are substantially dependent on the prevailing prices of oil
and natural gas which are unstable and subject to fluctuation. Fluctuations in oil or natural gas prices
could have an adverse effect on Surge’s operations and financial condition and the value and amount of
its reserves. Prices for crude oil fluctuate in response to global and North American supply of and
demand for oil, market performance and uncertainty and a variety of other factors which are outside the
control of Surge including, but not limited, to the world economy and the Organization of Petroleum
Exporting Countries’ (“OPEC”) ability to adjust supply to world demand, government regulation, political
stability and the availability of alternative fuel sources. In addition, the prices received by Surge for its oil
are subject to differentials against such benchmarks as WTI and Edmonton Par which can fluctuate
substantially and result in Surge realizing prices substantially below such benchmarks. Natural gas
prices are influenced primarily by factors within North America, including North American supply and
demand, economic performance, weather conditions and availability and pricing of alternative fuel
sources.
Decreases in oil and natural gas prices realized by Surge will result in reduced net production revenue
and may change the economics of producing from some wells, which could result in a reduction in the
volume of Surge’s reserves. Any further substantial declines in the prices of crude oil or natural gas could
also result in delay or cancellation of existing or future drilling, development or construction programs or
the curtailment of production. All of these factors could result in a material decrease in Surge’s net
production revenue, cash flows and profitability causing a reduction in its oil and gas acquisition and
development activities. In addition, bank borrowings available to Surge will in part be determined by
Surge’s borrowing base. A sustained material decline in prices from historical average prices could further
reduce such borrowing base, therefore reducing the bank credit available, including under the Credit
Facility, and could require that a portion of its bank debt be repaid.
Surge may enter into agreements to receive fixed prices on its oil and natural gas production to offset the
risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the
levels set in such agreements, Surge will not benefit from such increases.
Weakness in the Oil and Gas Industry
Recent market events and conditions, including global excess oil and natural gas supply, actions taken by
OPEC, slowing growth in emerging economies, market volatility and disruptions in Asia, sovereign debt
levels and political upheavals in various countries have caused significant weakness and volatility in
commodity prices. These events and conditions have caused a significant decrease in the valuation of oil
and gas companies and a decrease in confidence in the oil and gas industry. These difficulties have
been exacerbated in Canada by the recent changes in government at a federal level and, in the case of
Alberta, at the provincial level, and the resultant uncertainty surrounding regulatory, tax, royalty changes
and environmental regulation that have been announced or may be implemented by the new
governments. In addition, the inability to get the necessary approvals 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
downward price pressure on oil and gas produced in Western Canada and 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, rendering certain reserves uneconomic. In addition,
lower commodity prices have restricted, and may continue to restrict, the Corporation's cash flow resulting
in a reduced capital expenditure budget. Consequently, 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.
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. During the recent
presidential campaign a number of election promises were made and the new American administration
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has begun taking steps to implement certain of these promises. Included in the actions that the
administration has discussed are the renegotiation of the terms of NAFTA, withdrawal of the United
States from the TPP, imposition of a tax on the importation of goods into the United States, reduction of
regulation and taxation in the United States, and introduction of laws to reduce immigration and restrict
access into the United States for citizens of certain countries. It is presently unclear exactly what actions
the new administration in the United States will implement, and if implemented, how these actions may
impact Canada and in particular the oil and gas industry. Any actions taken by the new United States
administration may have a negative impact on the Canadian economy and on the businesses, financial
conditions, results of operations and the valuation of Canadian oil and gas companies, including Surge.
In addition to the political disruption in the United States, the citizens of the United Kingdom recently
voted to withdraw from the European Union and the Government of the United Kingdom has begun taken
steps to implement such withdrawal. Some European countries have also experienced the rise of anti-
establishment 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 Surge’s ability to market products internationally, increase costs for
goods and services required for operations, reduce access to skilled labour and negatively impact
business, operations, financial conditions and the market value of the Common Shares.
Environmental Concerns
Many aspects of the oil and natural gas business present environmental risks and hazards, including the
risk that Surge may be in noncompliance with an environmental law, regulation, permit, licence, or other
regulatory approval, possibly unintentionally or without knowledge. Such risks may expose Surge to fines
or penalties, third party liabilities or to the requirement to remediate, which could be material.
The operational hazards associated with possible blowouts, accidents, oil spills, natural gas leaks, fires,
or other damage to a well or a pipeline may require Surge to incur costs and delays to undertake
corrective actions, could result in environmental damage or contamination or could result in serious injury
or death to employees, consultants, contractors or members of the public, creating the potential for
significant liability to Surge. Also, the occurrence of any such incident could damage Surge’s reputation
in the surrounding communities and make it more difficult for Surge to pursue its operations in those
areas.
Compliance with environmental laws and regulations could materially increase Surge’s costs. Surge may
incur substantial capital and operating costs to comply with increasingly complex laws and regulations
covering the protection of the environment and human health and safety. In particular, Surge may be
required to incur significant costs to comply with future federal or provincial greenhouse gas emissions
reduction requirements or other regulations, if enacted.
Although Surge maintains insurance consistent with prudent industry practice, it is not fully insured
against certain environmental risks, either because such insurance is not available or because of high
premium costs. In particular, insurance against risks from environmental pollution occurring over time (as
opposed to sudden and catastrophic damages) is not available on economically reasonable terms.
Accordingly, Surge’s properties may be subject to liability due to hazards that cannot be insured against,
or that have not been insured against due to prohibitive premium costs or for other reasons. It is also
possible that changing regulatory requirements or emerging jurisprudence could render such insurance of
less benefit to Surge.
Dividends
Notwithstanding anything contained in this Annual Information Form, the payment and the amount of
dividends declared, if any, will be subject to the discretion of the Board and will depend on the Board’s
assessment of the Corporation’s outlook for growth, capital expenditure requirements, funds from
operations, potential opportunities, debt position and other conditions that the Board may consider
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relevant at such future time, including applicable restrictions that may be imposed under the Credit
Facility and on the ability of the Corporation to pay dividends. The amount of future cash dividends, if any,
may also vary depending on a variety of factors, including fluctuations in commodity prices, production
levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens and
foreign exchange rates. To the extent that external sources of capital become limited or unavailable,
Surge’s ability to make the necessary capital investments to maintain or expand oil and natural gas
reserves and to invest in assets, as the case may be, will be impaired. To the extent that Surge is
required to use funds from operations to finance capital expenditures or property acquisitions, the cash
available for dividends may be reduced.
In addition, the market value of the Common Shares may decline if the Corporation’s cash dividends
decline in the future, and that market value decline may be material. See “Dividend Policy.”
Royalty Regimes
There can be no assurance that the federal government and the provincial governments in the
jurisdictions in which the Corporation operates will not adopt new royalty regimes or modify the existing
royalty regimes which may have an impact on the economics of the Corporation's projects. The royalty
regime in Alberta, Saskatchewan and any other jurisdictions in which the Corporation’s oil and natural gas
assets are located may be subject to further review and changes which could adversely impact the
Corporation’s financial condition and operations. 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”.
Gathering and Processing Facilities, Pipeline Systems and Rail
Surge delivers its products through gathering and processing facilities, pipeline systems and, in certain
circumstances, by rail. The amount of oil and natural gas that Surge can produce and sell is subject to the
accessibility, availability, proximity and capacity of these gathering and processing facilities, pipeline
systems and railway lines. The lack of availability of capacity in any of the gathering and processing
facilities, pipeline systems and railway lines could result in the inability to realize the full economic
potential of Surge’s production or in a reduction of the price offered for its production. The lack of firm
pipeline capacity continues to affect the oil and natural gas industry and limit the ability to transport
produced oil and gas to market. In addition, the pro-rationing of capacity on inter-provincial pipeline
systems 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 or because of actions taken by regulators could
also affect Surge’s production, operations and financial results. As a result, 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 or uncertainty in
constructing new infrastructure systems and facilities could harm Surge’s business and, in turn, its
financial condition, operations and cash flows. Announcements and actions taken by the government of
Alberta relating to approval of infrastructure projects may continue to intensify, leading to increased
challenges to interprovincial and international infrastructure projects moving forward. In addition, while the
federal government has recently introduced draft legislation to overhaul the existing environmental
assessment process and replace the NEB with a new regulatory agency, the impact of the new proposed
regulatory scheme on proponents and the timing of receipt of approvals of major projects remains
unclear.
Following major accidents in Lac-Megantic, Quebec and North Dakota, the Transportation Safety Board
of Canada and the U.S. National Transportation Board have recommended additional regulations for
railway cars carrying crude oil. In June 2015, as a result of these recommendations, the Government of
Canada passed the Safe and Accountable Rail Act which increased insurance obligations on the
shipment of crude oil by rail and imposed a per tonne levy of $1.65 on crude oil shipped by rail to
compensate victims and for environmental cleanup in the event of a railway accident. In addition to this
legislation, new regulations have implemented the TC-117 standard for all rail tank cars carrying
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flammable liquids which formalized the commitment to retrofit, and eventually phase out DOT-111 tank
cars carrying crude oil. The increased regulation of rail transportation may reduce the ability of railway
lines to alleviate pipeline capacity issues and adds additional costs to the transportation of crude oil by
rail. On July 13, 2016, the Minister of Transport (Canada) issued Protective Direction No. 38, which
directed that the shipping of crude oil on DOT-111 tank cars end by November 1, 2016. Tank cars
entering Canada from the United States will be monitored to ensure they are compliant with Protective
Direction No. 38.
A portion of Surge’s production may, from time to time, be processed through facilities owned by third
parties and over which it does not have control. From time to time, 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 have a materially adverse effect on Surge’s
ability to process its production and deliver the same for sale. Midstream and pipeline companies may
take actions to maximize their return on investment which may in turn adversely affect producers and
shippers, especially when combined with a regulatory framework that may not always align with the
interests of particular shippers.
Fixed Price Hedging
From time to time, the Corporation may enter into agreements to receive fixed prices on its oil and natural
gas production to offset the risk of revenue losses if commodity prices decline. However, to the extent
that the Corporation engages in price risk management activities to protect itself from commodity price
declines, it may also be prevented from realizing the full benefits of price increases above the levels of
the derivative instruments used to manage price risk. In addition, the Corporation’s hedging
arrangements may expose it to the risk of financial loss in certain circumstances, including instances in
which: production falls short of the hedged volumes; there is a widening of price-basis differentials
between delivery points for production and the delivery point assumed in the hedge arrangement; the
counterparties to the hedging arrangements or other price risk management contracts fail to perform
under those arrangements; or a sudden unexpected event materially impacts oil and natural gas prices.
Similarly, from time to time the Corporation 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, the Corporation will not benefit from the fluctuating exchange rate.
Industry Regulation and Competition
There is strong competition relating to all aspects of the oil and natural gas industry. Surge will actively
compete for capital, skilled personnel, undeveloped land, reserve acquisitions, access to drilling rigs,
service rigs and other equipment, access to processing facilities and pipeline and refining capacity, and in
all other aspects of its operations with a substantial number of other organizations, many of which may
have greater technical and financial resources than Surge. Some of those organizations not only explore
for, develop and produce oil and natural gas but also carry on refining operations and market petroleum
and other products on a world-wide basis and as such have greater and more diverse resources on which
to draw. Surge’s ability to increase reserves and production in the future will depend not only on its ability
to develop its present properties, but also on its ability to select and acquire suitable producing properties
or prospects for exploratory drilling.
The marketability of oil and natural gas acquired or discovered will be affected by numerous factors
beyond the control of Surge. These factors include reservoir characteristics, market fluctuations, the
proximity and capacity of oil and natural gas pipelines and processing equipment and government
regulation. Oil and natural gas operations (exploration, production, pricing, marketing, transportation and
royalty rates) are subject to extensive controls and regulations imposed by various levels of government,
including those described above under the heading “Industry Conditions”, which may be amended from
time to time. Surge’s oil and natural gas operations may also be subject to compliance with federal,
provincial and local laws and regulations controlling the discharge of materials into the environment or
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otherwise relating to the protection of the environment. Changes to the regulation of the oil and gas
industry in jurisdictions in which Surge operates may adversely impact Surge’s ability to economically
develop existing reserves and add new reserves.
Variations in Foreign Exchange Rates and Interest Rates
Surge’s expenses will be denominated in Canadian dollars, while the price of oil and natural gas will
generally be denominated in U.S. dollars or impacted by the Canadian dollar to U.S. dollar exchange rate.
As the exchange rate for the Canadian dollar versus the U.S. dollar increases, Surge will generally
receive fewer Canadian dollars for its production. If the value of the Canadian dollar against the U.S.
dollar increases, the financial results of Surge may be negatively affected. Future fluctuations in the
Canadian/United States foreign exchange rate may impact the future value of Surge’s reserves as
determined by independent evaluators. In addition, variations in interest rates could result in a significant
change in the amount Surge will pay to service debt, potentially adversely affecting the value of the
Common Shares. Surge’s management may hedge interest rates to mitigate these risks.
Price Volatility of Publicly Traded Securities
In recent years, the securities markets in Canada and the United States have experienced a high level of
price and volume volatility, and the market price of securities of many companies, particularly those
considered to be development stage companies, has experienced wide fluctuations in price which have
not necessarily been related to the operating performance, underlying asset values or prospects of such
companies. There can be no assurance that continual fluctuations in price will not occur. It is likely that
the market price for the Common Shares will be subject to market trends generally, notwithstanding the
financial and operational performance of Surge.
Abandonment and Reclamation Costs
Surge will be responsible for compliance with terms and conditions of environmental and regulatory
approvals and all laws and regulations regarding abandonment and reclamation in respect of its
properties, which abandonment and reclamation costs may be substantial. A breach of such legislation or
regulations may result in the imposition of fines and penalties, including an order for cessation of
operations at the site until satisfactory remedies are made.
Credit Facility Risks
The Corporation currently has the Credit Facility and the amount authorized thereunder is dependent on
the borrowing base determined by its lenders. The Corporation is required to comply with covenants
under the Credit Facility which may, in certain cases, include certain financial ratio tests, which from time
to time either affect the availability, or price, of additional funding and in the event that the Corporation
does not comply with these covenants, the Corporation’s access to capital could be restricted or
repayment could be required. Events beyond the Corporation’s control may contribute to the failure of the
Corporation to comply with such covenants. A failure to comply with covenants could result in default
under the Credit Facility, which could result in the Corporation being required to repay amounts owing
thereunder. Even if the Corporation is able to obtain new financing, it may not be on commercially
reasonable terms or terms that are acceptable to the Corporation. If the Corporation is unable to repay
amounts owing under the Credit Facility, the lenders under the Credit Facility could proceed to foreclose
or otherwise realize upon the collateral granted to them to secure the indebtedness. The acceleration of
the Corporation’s indebtedness under one agreement may permit acceleration of indebtedness under
other agreements that contain cross default or cross-acceleration provisions. In addition, the Credit
Facility may impose operating and financial restrictions on the Corporation that could include restrictions
on the payment of dividends, repurchase or making of other distributions with respect to the Corporation’s
securities, incurring of additional indebtedness, the provision of guarantees, the assumption of loans,
making of capital expenditures, entering into of amalgamations, mergers, take-over bids or disposition of
assets, among others.
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The Corporation’s lenders use the Corporation’s reserves, commodity prices, applicable discount rate and
other factors, to periodically determine the Corporation’s borrowing base. A material decline in
commodity prices could reduce 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 bank indebtedness.
Substantial Capital Requirements; Liquidity
Surge may have to make substantial capital expenditures for the acquisition, exploration, development
and production of oil and natural gas reserves in the future. If revenues or reserves decline, Surge may
have limited ability to expend the capital necessary to undertake or complete future drilling programs.
There can be no 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 the company. Moreover, future activities may require
Surge to alter its capitalization significantly. The inability of the company to access sufficient capital for its
operations could have a material adverse effect on its financial condition, results of operations or
prospects.
Reserve Estimates
There are numerous uncertainties inherent in evaluating quantities of reserves and the net present value
of future net revenue to be derived therefrom, including many factors beyond the control of Surge. The
reserves information contained in the Reserves Report and set forth herein, including information
respecting the net present value of future net revenue from reserves, represents an estimate only. This
estimate is based on a number of assumptions relating to factors such as initial production rates,
production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures,
marketability of production, future prices of oil and natural gas, operating costs and royalties and other
government levies that may be imposed over the producing life of the reserves. These assumptions were
based on price forecasts in use at the date the Reserve Reports were prepared and many of these
assumptions are subject to change and are beyond the control of Surge. Ultimately, the actual reserves
attributable to Surge’s properties will vary from the estimates contained in the Reserves Report and those
variations may be material and affect the market price of the Common Shares.
Reserve Replacement
Surge’s future oil and natural gas reserves and production and the cash flows to be derived therefrom are
highly dependent on successfully acquiring or discovering new reserves. Without the continual addition of
new reserves, any existing reserves Surge may have at any particular time and the production therefrom
will decline over time as such existing reserves are exploited. A future increase in reserves will depend
not only on Surge’s ability to develop any properties it may have from time to time, but also on its ability to
select and acquire suitable producing properties or prospects. There can be no assurance that Surge’s
future exploration and development efforts will result in the discovery and development of additional
commercial accumulations of oil and natural gas.
Sour Natural Gas
Some of the Corporation’s current or future properties include wells that produce sour natural gas and
facilities that process sour natural gas. An accidental discharge or leak of sour natural gas can be fatal or
cause serious injury. The dangers associated with drilling for, producing, processing and transporting
sour natural gas necessitate increased environmental, health and safety compliance costs to Surge and
any accidental discharge or leak of sour natural gas could lead to significant liabilities to Surge. Surge
has implemented policies and protocols to address this risk, but it is not possible for any issuer to
eliminate all of the risks associated with producing, processing and transporting sour natural gas.
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Delay in Cash Receipts and Credit Worthiness of Counterparties
In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of Surge’s
properties, and by the operator to Surge, payments between any of such parties may also be delayed by
restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of
wells to a gathering system, blowouts or other accidents, recovery by the operator of expenses incurred
in the operation of Surge’s properties or the establishment by the operator of reserves for such expenses.
In addition, the insolvency or financial impairment of any counterparty owing money to Surge, including
industry partners and marketing agents, could prevent Surge from collecting such debts.
Geopolitical Risks
Political events throughout the world that cause disruptions in the supply of oil continuously affect the
marketability and price of oil and natural gas acquired or discovered by the Corporation. Conflicts, or
conversely peaceful developments, arising outside of Canada have a significant impact on the price of oil
and natural gas. Any particular event could result in a material decline in prices and result in a reduction
of the Corporation’s net production revenue.
In addition, the Corporation’s oil and natural gas properties, wells and facilities could be the subject of a
terrorist attack. If any of the Corporation’s properties, wells or facilities are the subject of terrorist attack it
may have a material adverse effect on the Corporation’s business, financial condition, results of
operations and prospects. The Corporation does not have insurance to protect against the risk from
terrorism.
Issuance of Debt
From time to time Surge may enter into transactions to acquire assets or shares of other corporations.
These transactions may be financed partially or wholly through debt, which may increase debt levels
above industry standards. Surge’s articles and by-laws do not limit the amount of indebtedness it may
incur. The level of Surge’s indebtedness from time to time could impair its ability to obtain additional
financing in the future on a timely basis to take advantage of business opportunities that may arise.
Possible Failure to Realize Anticipated Benefits of Acquisitions and Dispositions
The Corporation has recently completed a number of acquisitions and dispositions and may complete
future acquisitions and dispositions to strengthen its position in the oil and natural gas industry and to
create the opportunity to realize certain benefits including, among other things, potential cost savings.
Achieving the benefits of recent and any future acquisitions the Corporation may complete will depend in
part on successfully consolidating functions and integrating operations and procedures 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 assets and operations with those of the Corporation. The
integration of acquired assets 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 recent and any future
acquisitions. Management continually assesses the value and contribution of services provided by third
parties and assets required to provide such services. In this regard, non-core assets may be periodically
disposed of so that the Corporation can focus its efforts and resources more efficiently. Depending on the
state of the market for such non-core assets, certain of Surge’s non-core assets may realize less on
disposition than their carrying value on the consolidated financial statements of the Corporation.
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Cost of New Technologies
The petroleum industry is characterized by rapid and significant technological advancements and
introductions of new products and services utilizing new technologies. Other 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 Surge will be able to respond to such competitive pressures and implement such
technologies on a timely basis or at an acceptable cost. If Surge implements such technologies, there is
no assurance that it will do so successfully. One or more of the technologies currently utilized by Surge or
implemented in the future may become obsolete. In such case, Surge’s business, financial condition and
results of operations could be affected adversely and materially. If Surge is unable to utilize the most
advanced commercially available technology, or is unsuccessful in implementing certain technologies,
Surge’s business, financial condition and results of operations could also be adversely affected in a
material way.
Information Technology Systems and Cyber-Security
Surge has become increasingly dependent upon the availability, capacity, reliability and security of its
information technology infrastructure and its ability to expand and continually update this infrastructure, to
conduct daily operations. Surge depends on various information technology systems to estimate reserve
quantities, process and record financial data, manage the land base, analyze seismic information,
administer contracts with operators and lessees and communicate with employees and third-party
partners.
Further, Surge is subject to a variety of information technology and system risks as a part of its normal
course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security
breach, and destruction or interruption of its information technology systems by third parties or insiders.
Unauthorized access to these systems by employees or third parties could lead to corruption or exposure
of confidential, fiduciary or proprietary information, interruption to communications or operations or
disruption to Surge’s business activities or competitive position. Further, disruption of critical information
technology services, or breaches of information security, could have a negative effect on Surge’s
performance and earnings, as well as on Surge’s reputation. Surge has technical and process controls in
line with industry-accepted standards to protect its information assets and systems; however, these
controls may not adequately prevent cyber-security breaches. The significance of any such event is
difficult to quantify, but may in certain circumstances be material and could have a material adverse effect
on Surge’s business, financial condition and results of operations.
Hydraulic Fracturing
The proliferation of the use of hydraulic fracturing as a recovery technique employed in oil and natural gas
drilling has given rise to increased public scrutiny of its environmental aspects, particularly with respect to
its potential impact on local aquifers. Surge utilizes hydraulic fracturing in a significant portion of the light
oil wells it drills and completes. Negative public perception of hydraulic fracturing may place pressure on
governments in the jurisdictions where Surge operates to implement additional regulatory requirements or
limitations on the utilization of hydraulic fracturing, which in turn could restrict Surge’s operations and
increase its costs.
Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to
operational delays, increased operating costs, third party or governmental claims, and could increase
costs of compliance and doing business as well as delay the development of oil and natural gas
resources from shale formations, which are not commercial without the use of hydraulic fracturing.
Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that Surge is
ultimately able to produce from its reserves.
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Dilution
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 may determine. In addition, Surge
may issue additional Common Shares from time to time pursuant to Surge’s stock option plan and stock
incentive plan. The issuance of these Common Shares would result in dilution to holders of Common
Shares.
Net Asset Value
Surge’s net asset value will vary depending upon a number of factors beyond the control of Surge’s
management, including oil and natural gas prices. The trading price of the Common Shares is also
determined by a number of factors which are beyond the control of management and such trading price
may be greater than or less than the net asset value of Surge.
Reliance on Management
Shareholders will be dependent on the management of Surge in respect of the administration and
management of all matters relating to Surge and its properties and operations. Investors who are not
willing to rely on the management of Surge should not invest in Common Shares.
Permits and Licenses
The operations of Surge may require licenses and permits from various governmental authorities. There
can be no assurance that Surge will be able to obtain all necessary licenses and permits that may be
required to carry out exploration and development at its projects.
Title to Properties
Although title reviews will be done according to industry standards prior to the purchase of most oil and
natural gas producing properties or the commencement of drilling wells as determined appropriate by
management, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will
not arise to defeat a claim of Surge which could result in a reduction of Surge’s interest in a property or
well and the revenue received by Surge therefrom.
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.
Aboriginal Claims
Aboriginal peoples have claimed aboriginal title and rights to resources and various properties in Western
Canada. Such claims, in relation to any of Surge’s lands, if successful, could have an adverse effect on
its operations.
Income Taxes
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The Corporation files all required income tax returns and believes that it is in full compliance with the
provisions of the Tax Act 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
the Corporation, 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 the Corporation.
Furthermore, tax authorities having jurisdiction over the Corporation may disagree with how the
Corporation calculates its income for tax purposes or could change administrative practices to the
Corporation's detriment.
Corporate Matters
Certain of the directors and officers of Surge are also directors and officers of other oil and gas
companies involved in natural resource exploration and development, and conflicts of interest may arise
between their duties as officers and directors of Surge, as the case may be, and as officers and directors
of such other companies.
Failure to Maintain Listing of the Common Shares and the Debentures
The Common Shares and the Debentures are currently listed for trading on the facilities of the TSX. The
failure of Surge to meet the applicable listing or other requirements of the TSX in the future may result in
the Common Shares and/or the Debentures ceasing to be listed for trading on the TSX, which would have
a material adverse effect on the value of the Common Shares and/or Debentures. There can be no
assurance that the Common Shares and Debentures will continue to be listed for trading on the TSX.
Structure of Surge
From time to time, Surge may take steps to organize its affairs in a manner that minimizes taxes and
other expenses payable with respect to the operation of Surge and its subsidiaries. If the manner in which
Surge structures its affairs is successfully challenged by a taxation or other authority, Surge and the
holders of Common Shares may be adversely affected.
Changes in Legislation
It is possible that the Canadian federal and provincial government or regulatory authorities could choose
to change the Canadian federal income tax laws, royalty regimes, liability management, environmental
and climate change laws or other laws applicable to oil and gas companies and that any such changes
could materially adversely affect Surge, its shareholders and the market value of the Common Shares.
Additional information on the risks, assumptions and uncertainties are found in this Annual Information
Form under the heading “Special Note Regarding Forward Looking Statements”.
Alternatives to and Changing Demand for Petroleum Products
Full conservation measures, alternative fuel requirements, increasing consumer demand for alternatives
to oil and natural gas and technological advances in fuel economy and renewable energy generation
devices could reduce the demand for oil, natural gas and 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. Surge cannot predict the impact of changing
demand for oil and natural gas products, and any major changes may have a material adverse effect on
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its business, financial condition, results of operations and cash flows by decreasing profitability,
increasing costs, limiting access to capital and decreasing the value of Surge’s assets.
Forward-Looking Information
Shareholders and prospective investors are cautioned not to place undue reliance on Surge’s forward-
looking information. By its nature, forward-looking information involves numerous assumptions, known
and unknown risks 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, assumption and uncertainties are found under the heading "Special
Note Regarding Forward Looking Statements" of this Annual Information Form.
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
There are no outstanding legal proceedings material to the Corporation to which the Corporation is a
party or in respect of which any of its properties are subject, nor are there any such proceedings known to
the Corporation to be contemplated.
During the year ended December 31, 2017, there were (i) no penalties or sanctions imposed against the
Corporation by a court relating to securities legislation or by a securities regulatory authority; (ii) no other
penalties or sanctions imposed by a court or regulatory body against the Corporation that it believes
would likely be considered important to a reasonable investor in making an investment decision; and (iii)
no settlement agreements entered into by the Corporation with a court relating to securities legislation or
with a securities regulatory authority.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
Each of James Pasieka, a director of the Corporation, and Michael Bennett, the Corporate Secretary of
the Corporation, is a partner of the national law firm McCarthy Tétrault LLP, which law firm rendered legal
services to the Corporation.
Except as disclosed above or as may be disclosed elsewhere in this AIF, none of the directors, executive
officers or principal shareholders of the Corporation, and no associate or affiliate of any of them, has or
has had any material interest in any transaction or any proposed transaction which has materially affected
or is reasonably expected to materially affect the Corporation or any of its affiliates.
AUDITOR, TRANSFER AGENT AND REGISTRAR
KPMG LLP are the auditors of the Corporation and have confirmed with respect to the Corporation, that
they are independent within the meaning of the relevant rules and related interpretations prescribed by
the relevant professional bodies in Canada and any applicable legislation or regulations.
The transfer agent and registrar for the Common Shares is Computershare Trust Company of Canada at
its principal offices in Calgary, Alberta and Toronto, Ontario.
INTEREST OF EXPERTS
The Reserves Report and certain reserves estimates contained in filings made by the Corporation under
National Instrument 51-102 – Continuous Disclosure Requirements during the year ended December 31,
2017 were prepared by Sproule. As at the date of this Annual Information Form, the directors, officers,
employees and consultants of Sproule who participated in the preparation of the Reserves Report or such
reserves estimates or who were in a position to directly influence the preparation or outcome of the
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preparation of the Reserves Report or such reserves estimates, as a group, owned, directly or indirectly,
less than 1% of the outstanding Common Shares.
KPMG LLP are independent of the Corporation pursuant to the rules of professional conduct of the
Institute of Chartered Accountants of Alberta.
ADDITIONAL INFORMATION
Additional information concerning the Corporation may be found under the Corporation’s profile on
SEDAR at www.sedar.com. Additional information, including information concerning directors’ and
officers’ remuneration and indebtedness, principal holders of the Corporation’s securities and securities
authorized for issuance under equity compensation plans, will be contained in the information circular of
the Corporation for the annual general meeting of the holders of Common Shares scheduled to be held in
2018. Additional financial information is provided in the Corporation’s comparative financial statements
and management’s discussion and analysis for the year ended December 31, 2017.
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SCHEDULE “A”
Form 51-101F2
SCHEDULE “B”
FORM 51-101F3
Report of Management and Directors on Reserves Data and Other Information
Terms to which a meaning is ascribed in National Instrument 51-101 - Standards of Disclosure for Oil and
Gas Activities have the same meaning herein.
Management of Surge Energy Inc. (the “Corporation”) is responsible for the preparation and disclosure
of information with respect to the Corporation’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, 2017, estimated using forecast
prices and costs.
Sproule Associates Limited, an independent qualified reserves evaluator, has evaluated and reviewed the
Corporation’s reserves data. The report of the independent qualified reserves evaluator is presented in
Schedule ”A” to the Annual Information Form of the Corporation for the year ended December 31, 2017
(the “AIF”).
The Reserves Committee of the Board of Directors of the Corporation has:
(a)
(b)
reviewed the Corporation’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 applicable reserves data with management and with Sproule Associates Limited.
The Reserves Committee of the Board of Directors has reviewed the Corporation’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, incorporated into
the AIF, containing reserves data and other oil and gas information;
the filing of Form 51-101F2, which are the reports of the independent qualified reserves
evaluators of on the reserves data; and
(c)
the content and filing of this report.
[Balance of Page Intentionally Left Blank.]
Because the reserves data are based on judgements regarding future events, actual results will vary and
the variations may be material. However, any variations should be consistent with the fact that reserves
are categorized according to the probability of their recovery.
(signed) “Paul Colborne”
Paul Colborne, President & Chief Executive
Officer
(signed) “Paul Ferguson”
Paul Ferguson, Vice-President, Finance and
Chief Financial Officer
(signed) “Daryl Gilbert”
Daryl Gilbert, Director & Chair of the Reserves
Committee
(signed) “P. Daniel O’Neil”
P. Daniel O’Neil, Director
March 14, 2018
SCHEDULE “C”
Audit Committee Charter
Role and Objective
The Audit Committee is a committee of the Board of Directors of Surge Energy Inc. (the “Corporation”) to
which the Board has delegated its responsibility for oversight of the nature and scope of the annual audit,
management’s reporting on internal accounting standards and practices, financial information and
accounting systems and procedures, financial reporting and statements and recommending, for Board
approval, the audited consolidated financial statements and other mandatory disclosure releases
containing financial information of the Corporation. The objectives of the Audit Committee are as follows:
1.
2.
3.
4.
5.
to assist directors in fulfilling their legal and fiduciary obligations (especially for accountability) in
respect of the preparation and disclosure of the financial statements of the Corporation and
related matters;
to oversee the audit efforts of the external auditors of the Corporation;
to maintain free and open means of communication among the directors, the external auditors,
the financial and senior management of the Corporation;
to satisfy itself that the external auditors are independent of the Corporation; and
to strengthen the role of the outside directors by facilitating in depth discussions between
directors on the Committee, management and external auditors.
The function of the Committee is one of oversight of management and the external auditors in the
execution of their responsibilities. Management is responsible for the preparation, presentation and
integrity of the financial statements of the Corporation, maintaining appropriate accounting and financial
reporting principles and policies and implementing appropriate internal controls and procedures. The
external auditors are responsible for planning and carrying out a proper audit of the annual financial
statements of the Corporation and reviewing the interim financial statements of the Corporation prior to
their filing with securities regulatory authorities and other procedures.
Composition of the Committee
1.
2.
3.
4.
The Audit Committee shall consist of at least three directors. The Board shall appoint one
member of the Audit Committee to be the Chair of the Audit Committee.
Each director appointed to the Audit Committee by the Board must be independent. A director is
independent if the director has no direct or indirect material relationship with the Corporation. A
material relationship means a relationship which could, in the view of the Board, reasonably
interfere with the exercise of the director’s independent judgment. In determining whether a
director is independent of management, the Board shall make reference to National Instrument
52-110 – Audit Committees or the then current legislation, rules, policies and instruments of
applicable regulatory authorities.
Each member of the Audit Committee shall be “financially literate”. In order to be financially
literate, a director must be, at a minimum, able to read and understand financial statements that
present a breadth and complexity of accounting issues generally comparable to the breadth and
complexity of issues expected to be raised by the Corporation’s financial statements.
A director appointed by the Board to the Audit Committee shall be a member of the Audit
Committee until replaced by the Board or until his or her resignation.
Meetings of the Committee
1.
2.
The Audit Committee shall convene a minimum of four times each year at such times and places
as may be designated by the Chair of the Audit Committee and whenever a meeting is requested
by the Board, a member of the Audit Committee, the auditors, or a senior officer of the
Corporation. Meetings of the Audit Committee shall correspond with the review of the quarterly
financial statements and management discussion and analysis of the Corporation.
Notice of each meeting of the Audit Committee shall be given to each member of the Audit
Committee. The auditors shall be given notice of each meeting of the Audit Committee at which
financial statements of the Corporation are to be considered and such other meetings as
determined by the Chair and shall be entitled to attend each such meeting of the Audit
Committee.
3.
Notice of a meeting of the Audit Committee shall:
(a)
(b)
(c)
(d)
be in writing;
state the nature of the business to be transacted at the meeting in reasonable detail;
to the extent practicable, be accompanied by copies of documentation to be considered
at the meeting; and
be given at least two business days prior to the time stipulated for the meeting or such
shorter period as the members of the Audit Committee may permit.
4.
5.
6.
7.
8.
A quorum for the transaction of business at a meeting of the Audit Committee shall consist of a
majority of the members of the Audit Committee. However, it shall be the practice of the Audit
Committee to require review, and, if necessary, approval of certain important matters by all
members of the Audit Committee.
A member or members of the Audit Committee may participate in a meeting of the Audit
Committee by means of such telephonic, electronic or other communication facilities, as permits
all persons participating in the meeting to communicate adequately with each other. A member
participating in such a meeting by any such means is deemed to be present at the meeting.
In the absence of the Chair of the Audit Committee, the members of the Audit Committee shall
choose one of the members present to be Chair of the meeting. In addition, the members of the
Audit Committee shall choose one of the persons present to be the Secretary of the meeting.
The Chairman of the Board, senior management of the Corporation and other parties may attend
meetings of the Audit Committee; however the Audit Committee (i) shall meet with the external
auditors independent of management as necessary, in the sole discretion of the Committee, but
in any event, not less than quarterly; and (ii) may meet separately with management.
Minutes shall be kept of all meetings of the Audit Committee and shall be signed by the Chair and
the Secretary of the meeting.
Duties and Responsibilities of the Committee
1.
It is the responsibility of the Audit Committee to oversee the work of the external auditors,
including resolution of disagreements between management and the external auditors regarding
financial reporting. The external auditors shall report directly to the Audit Committee.
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2.
3.
The Audit Committee shall, in the exercise of its powers, authorities and discretion so authorized,
conform to any regulations or restrictions that may from time to time be made or imposed upon it
by the Board or the legislation, policies or regulations governing the Corporation and its business.
It is the responsibility of the Audit Committee to satisfy itself on behalf of the Board that the
Corporation’s system of internal controls over financial reporting and disclosure controls and
procedures are satisfactory for the purpose of:
(a)
(b)
identifying, monitoring and mitigating the principal risks;
ensuring compliance with legal, ethical and regulatory requirements;
and to review with the external auditors their assessment of the internal controls over financial
reporting and the disclosure controls of the Corporation, their written reports containing
recommendations for improvement, and management’s response and any follow-up to any
identified weaknesses.
4.
It is the responsibility of the Audit Committee to review the annual financial statements of the
Corporation and, if deemed appropriate, recommend the financial statements to the Board for
approval. This process should include but be not to be limited to:
(a)
(b)
(c)
(d)
reviewing and accepting, if appropriate, the annual audit plan of the external auditors of
the Corporation, including the scope of audit activities, and monitor such plan’s progress
and results during the year;
reviewing changes in accounting principles, or in their application, which may have a
material impact on the current or future years’ financial statements;
reviewing significant accruals, reserves or other estimates such as any impairment
calculation;
reviewing the methods used to account for significant unusual or non-recurring
transactions;
(e)
ascertaining compliance with covenants under loan agreements;
(f)
(g)
reviewing disclosure requirements for commitments and contingencies;
reviewing adjustments raised by the external auditors, whether or not included in the
financial statements;
(h)
reviewing unresolved differences between management and the external auditors;
(i)
(j)
obtain explanations of significant variances with comparative reporting periods;
review of business systems changes and implications;
(k)
review of authority and approval limits;
(l)
review the adequacy and effectiveness of the accounting and internal control policies of
the Corporation and procedures through inquiry and discussions with the external
auditors and management;
(m)
confirm through private discussion with the external auditors and the management that
no management restrictions are being placed on the scope of the external auditors’ work;
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(n)
(o)
review of tax policy issues; and
review of emerging accounting issues that could have an impact on the Corporation.
5.
It is the responsibility Audit Committee to review the interim financial statements of the
Corporation and, if deemed appropriate, to recommend the financial statements to the Board for
approval and to review all related management discussion and analysis. The Audit Committee
must be satisfied that adequate procedures are in place for the review of the Corporation’s
disclosure of all other financial information and shall periodically assess the accuracy of those
procedures.
6.
The Audit Committee shall have the authority to:
(a)
(b)
(c)
inspect any and all of the books and records of the Corporation, its subsidiaries and
affiliates;
discuss with the management and senior staff of the Corporation, its subsidiaries and
affiliates, any affected party and the external auditors, such accounts, records and other
matters as any member of the Audit Committee considers necessary and appropriate;
engage independent counsel and other advisors as it determines necessary to carry out
its duties; and
(d)
to set and pay the compensation for any advisors employed by the Audit Committee.
7.
With respect to the appointment of external auditors by the Board, the Audit Committee shall:
(a)
(b)
(c)
(d)
(e)
recommend to the Board the appointment of the external auditors;
review the performance of the external auditors and make recommendations to the Board
regarding the replacement or termination of the external auditors when circumstances
warrant;
oversee the independence of the external auditors by, among other things, requiring the
external auditors to deliver to the Audit Committee, on a periodic basis, a formal written
statement delineating all relationships between the external auditors and the Corporation
and its subsidiaries;
recommend to the Board the terms of engagement of the external auditor, including the
compensation of the auditors and a confirmation that the external auditors shall report
directly to the Committee; and
when there is to be a change in auditors, review the issues related to the change and the
information to be included in the required notice to securities regulators of such change.
8.
9.
Audit Committee shall review annually with the external auditors their plan for their audit and,
upon completion of the audit, their reports upon the financial statements of the Corporation and
its subsidiaries.
The Audit Committee must pre-approve all non-audit services to be provided to the Corporation
or its subsidiaries by external auditors. The Audit Committee may delegate, to one or more
members, the authority to pre-approve non-audit services, provided that the member report to the
Audit Committee at the next scheduled meeting and such pre-approval and the member comply
with such other procedures as may be established by the Audit Committee form time to time.
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10.
11.
The Audit Committee shall review the risk management policies and procedures of the
Corporation (i.e. hedging, litigation and insurance), including the annual review of insurance
coverage and make appropriate recommendations to the Board with respect thereto.
The Audit Committee shall receive regular updates with respect to information technology
matters, including with respect to the Corporation's cyber security programs to address potential
cyber-related risks.
12.
The Audit Committee shall establish and maintain procedures for:
(a)
(b)
the receipt, retention and treatment of complaints received by the Corporation regarding
accounting controls, or auditing matters; and
the confidential, anonymous submission by employees of the Corporation of concerns
regarding questionable accounting or auditing matters.
The Audit Committee shall review and approve the Corporation’s hiring policies regarding
employees and former employees of the present and former external auditors or auditing matters.
The Chairman of the Audit Committee shall review and approve the expenses incurred by the
President and Chief Executive Officer.
The Audit Committee shall periodically report the results of reviews undertaken and any
associated recommendations to the Board.
The Audit Committee shall assess, on an annual basis, the adequacy of this Mandate and the
performance of the Audit Committee.
13.
14.
15.
16.
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