Canada Gazette, Part I, Volume 152, Number 20: Indian Oil and Gas Regulations

May 19, 2018

Statutory authority
Indian Oil and Gas Act

Sponsoring departments
Department of Indigenous Services Canada
Department of Indian Affairs and Northern Development

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Issues

While provincial acts and regulations governing the conservation and development of oil and gas resources have been, over the past 20 years, enhanced and adapted to industry and technological developments, the federal regulatory regime for oil and gas development activities on First Nation reserve lands has not. This has resulted in an uneven playing field for oil and gas industry investment on First Nation reserve lands compared to equivalent lands in the surrounding province.

On May 14, 2009, amendments to modernize the Indian Oil and Gas Act (1974) [IOGA, 1974] received royal assent, resulting in a new Indian Oil and Gas Act (2009) [IOGA, 2009]. The IOGA, 2009 is not, however, currently in force, as it is dependent upon the coming into force of new regulations that would replace the existing Indian Oil and Gas Regulations, 1995 (1995 Regulations). This Regulatory Impact Analysis Statement addresses these new regulations.

Under the current federal regime,

A new federal regulatory regime is needed to lift barriers to industry investment on First Nation reserve lands while providing the federal government with modern tools to efficiently and effectively encourage industry compliance and to take appropriate action to address non-compliance.

Background

As the regulator of oil and gas exploration and development on First Nation reserve lands, the Government of Canada fulfills the Crown's fiduciary and statutory obligations to First Nations regarding their oil and gas resources. Indian Oil and Gas Canada, a special operating agency of Indigenous and Northern Affairs Canada, administers the Indian Oil and Gas Act (the Act). According to Indian Oil and Gas Canada's analysis, oil and gas may be present in approximately 300 First Nation reserves in British Columbia, Alberta, Saskatchewan, Manitoba, Ontario and the Northwest Territories. There are approximately 50 First Nations with active oil and gas exploration or production, mainly in Alberta and Saskatchewan. In fiscal year 2016–17, $59 million in oil and gas royalties, bonuses and rentals were collected by Indian Oil and Gas Canada on behalf of the producing First Nations, and $41 million were invested by industry to drill and complete 26 wells on First Nation reserve lands.

While external factors such as world energy prices, competitiveness of provincial regimes and access to markets may partially explain the limited pace of exploration and development of oil and gas resources on First Nation reserve lands, regulatory barriers faced by industry on federal lands are likely a contributing factor.

The Indian Oil and Gas Act was enacted in 1974, during the first global energy crisis, to provide the tools necessary to operate in a heavily regulated oil and gas industry. Although transactions have grown in volume, variety and complexity, the Act remained unchanged for 35 years while provincial acts and associated regulations were enhanced and adapted to industry and technological developments and were provided with modern redress mechanisms.

This has resulted in an uneven playing field for First Nations wanting to attract industry investment, as the existing legislative and regulatory regime governing oil and gas activity on First Nation reserve lands does not provide the level of clarity and certainty that modern industry requires and expects when making its investment decisions. The following are a few examples:

Further, Canada currently lacks the required authorities to audit a company conducting business on First Nation reserve lands. With such large sums of money involved in oil and gas, auditing is one of the essential tools to confirm that First Nations are indeed receiving the proper return in exchange for their natural resources.

The development of new regulations began in parallel with the IOGA, 2009 undergoing the parliamentary review and approval processes. In continuation with and building on the legislative development process, regulatory development has been done in partnership with oil- and gas-producing First Nations, and their level of participation has been unprecedented. First Nations were funded and were provided with opportunities to review and provide feedback on the policy intent behind the regulations, on the regulatory drafting instructions, and on drafts of proposed regulations. First Nations' funding included provisions for them to obtain independent legal and technical expertise and advice.

To facilitate the regulatory drafting process, given that oil and gas is a highly complex and technical industry, the regulations were subdivided into nine themes:

  1. Drainage and compensatory royalty
  2. Subsurface tenure
  3. Surface tenure
  4. Exploration
  5. Environment
  6. Enforcement
  7. Conservation
  8. Moneys management
  9. Royalty

To bring the IOGA, 2009 into force with minimal delay, Indigenous and Northern Affairs Canada proposed — and oil- and gas-producing First Nations agreed — that regulatory development would occur incrementally and that the IOGA, 2009 would be brought into force once core regulations had been drafted.

Core regulations have now been completed and consist of new provisions in the areas of subsurface tenure; drainage and compensatory royalty; First Nations' audit; and royalty reporting requirements to facilitate royalty verification. In addition, to cover the whole range of oil and gas activities on First Nation reserve lands and to ensure that there would be no regulatory gaps once brought into force, the provisions pertaining to the other themes are carried over from the 1995 Regulations, relatively unchanged, but with minor edits

The Government of Canada continues to work with First Nation stakeholders on the development of new regulations that would progressively replace sections of the regulations carried over from the 1995 Regulations. However, it is challenging at this time to be precise on the timing of subsequent regulatory development and amendments.

Objectives

The Indian Oil and Gas Regulations (the proposed Regulations) will entirely replace the existing Indian Oil and Gas Regulations, 1995, which will be repealed.

Approval of the regulatory proposal outlined in this Regulatory Impact Analysis Statement would enable the bringing into force of the IOGA, 2009, resulting in a more efficient and effective regulatory regime for First Nations oil and gas exploration and development. In addition, the on-reserve regime would also become more aligned with the regulatory environment off reserves.

Specific objectives of the proposed new federal regulatory regime are to

Description

The Indian Oil and Gas Regulations, 1995 are repealed and replaced with the proposed Regulations, which will be fully compatible with the IOGA, 2009. The proposed Regulations include new regulations in addition to provisions carried over from the 1995 Regulations.

To ensure that First Nations and industry have a predictable regulatory environment in which to make investment decisions, one that is more aligned with the regulatory environment off reserves, the proposed Regulations would

To provide a more robust and flexible compliance and enforcement regime that includes criteria for regulatory decision-making, a definition of the rights and responsibilities of all parties, and clear authorities and tools to encourage compliance, the new elements of the proposed Regulations would

In June 2006, the Standing Joint Committee for the Scrutiny of Regulations (the Committee) made a number of recommendations regarding the Indian Oil and Gas Regulations, 1995. Most of the recommendations pointed to inconsistencies between the English and French versions of the 1995 Regulations, and there were minor language issues in the English text. While the rewrite of the Act and the Regulations have largely eliminated the provisions where these issues were noted by the Committee, all of the Committee's recommendations were taken into account and addressed in the drafting of the new regulations.

Benefits and costs

In recent years, crude oil prices have undergone significant decreases due to world oil production exceeding world oil consumption. First Nations, which account for about 1% of the oil-producing sector in Canada, have been impacted at least as much as other jurisdictions. Although the new regulations are creating an improved climate for industry investment on First Nation reserve lands, other factors such as world oil prices and access to markets will have a major impact on the sector. As each First Nation's situation is unique due to variations in both their oil and gas leases and their production volumes, the fluctuations in world oil prices have and will continue to have varying impacts on First Nations. Although the regulatory proposal will not change these fluctuations, it may help to alleviate challenges the industry currently faces.

Benefits

Indian Oil and Gas Canada anticipates that one of the benefits of the proposed Regulations would be an improved investment climate due to a regulatory environment that is more closely aligned with provincial requirements. This harmonization would, in turn, improve the functioning of oil and gas activities on reserves and create a more positive investment climate for the oil and gas industry and for First Nations. The alignment of industry reporting requirements with current practices in the oil- and gas-producing provinces, enabled by the IOGA, 2009 and the proposed new Regulations, is expected to reduce the cost of doing business on First Nation reserve lands. In the absence of harmonization, industry has had to employ duplicate processes and systems — one for their on-reserve projects and another for their projects in the rest of the province. These changes are expected to save industry an estimated $55.6 million in total present value over the next 10 years, an annualized savings of $7.86 million (7% discount rate measured in 2012 Canadian dollars).

Costs

For companies already operating on reserve lands, some additional requirements would need to be met. However, with the exception of a new requirement for companies to apply for subsurface contracts in relation to a water disposal well, these requirements mostly codify procedures that are already being followed through administrative practice and voluntary compliance, such as right-of-entry charges for surface access, reporting unforeseen incidents and fixing surface access rates when a subsurface contract is issued. It is anticipated that the incremental costs of the additional requirements would be minimal and have been estimated at a total present value of $433,000, or $2,800 (mostly representing the additional application time for a subsurface contract) for each of the approximately 155 companies expected to be impacted.

Net outcome

It is expected that administrative efficiency, through the reduction of duplicate processes and clarified procedures, will more than compensate for any incremental costs and will result in net present value savings of over $55.2 million to the industry. Small to medium-size industry operators stand to benefit the most, since they are least capable of absorbing the costs of maintaining duplicate processes and systems. It is estimated that small businesses will receive approximately 73% of the administrative burden cost savings, a total saving valued at almost $40 million. In addition to this net positive outcome, the increased certainty and transparency will result in an improved environment for on-reserve investment.

Throughout Indian Oil and Gas Canada's engagement process, industry has not expressed any concerns related to the net outcome of the proposed new Regulations.

"One-for-One" Rule

This proposal is considered an "OUT" under the "One-for-One" Rule, as it results in a net positive reduction in administrative burden costs. According to Indigenous and Northern Affairs Canada's analysis using the Regulatory Cost Calculator (as per the methodology described in the Red Tape Reduction Regulations), it has been assessed that as a result of the proposed Regulations, companies involved in oil and gas activities on First Nation reserve lands could save an annualized equivalent of over $5.6 million (based on a 7% discount rate, measured in 2012 Canadian dollars).

Annualized administrative costs
(constant 2012 dollars)

$5,606,779

Annualized administrative costs per business
(constant 2012 dollars)

$30,977

There are currently some 200 oil and gas companies with active agreements on First Nation reserve lands, and it is estimated that 25% of these reserve lease and land holdings are held by First Nation-owned companies. For the purposes of costing the impact of the proposed Regulations, a simple per proponent perspective was adopted. While some regulatory transactions, such as royalty reporting, occur several times a year, others are annual, and others only occur once as part of the life cycle of an oil and gas agreement. Assumptions made in the Regulatory Cost Calculator are based on available data on transactions (statistics on frequency of information submissions, frequency and number of required authorizations) over the course of recent years as well as on estimates of time required to perform certain tasks (e.g. preparing a free form letter versus filling out a prescribed form). The salary source is the 2014 Mercer Total Compensation Survey for the Energy Sector (bonuses, stock options or other compensation considerations were not included).

The decrease in the administrative burden will result in savings for companies involved in oil and gas activities on reserves, as a consequence of a number of updates to the Regulations in support of a more efficient regime for oil and gas activities on reserves. These updates would include

The introduction of a requirement for companies to apply for a subsurface contract for the disposal of water, in addition to the technical approval of a service well, has the potential to increase administrative application costs for this type of subsurface contract for industry involved in oil and gas activities on First Nation reserve lands. These new administrative burden costs, totalling an annual amount of approximately $44,000, were deducted from the total cost savings achieved through the other measures.

Small business lens

The small business lens does not apply to this proposal, as there are no costs to small business.

Consultation

Initiated in 2008, regulatory development under this initiative was undertaken in close collaboration with the Indian Resource Council — an Indigenous organization that advocates on behalf of some 189 member First Nations with oil and gas resources or the potential for such resources. Indian Oil and Gas Canada and the Indian Resource Council established the Joint Technical Committee, made up of departmental subject matter experts and oil and gas technicians from some of the major oil- and gas-producing First Nations, to review and provide input during the development of the proposed Regulations. Funding was provided to the First Nation members of the Joint Technical Committee so they could obtain independent technical and legal advice in order to review and provide feedback on the policy intent behind the Regulations, on the regulatory drafting instructions, and on drafts of proposed regulations.

Consultations on modernizing the on-reserve oil and gas regime have been among the most comprehensive ever conducted by Indigenous and Northern Affairs Canada. First Nations were consulted directly during the development of the proposed Regulations to ensure that they were informed, meaningfully involved and had every opportunity to participate in the development of the proposed Regulations. Also, Indian Oil and Gas Canada held 10 information symposiums to discuss the proposed changes and answer questions, engaged and distributed information packages to more than 250 stakeholders, conducted over 80 one-on-one meetings, and held 6 technical workshops. Letters reporting on regulatory development progress were provided regularly, and annual updates were presented at the Indian Resource Council's general meetings. Quarterly newsletters for First Nations and industry with active oil and gas interests on reserve have been, and continue to be, provided.

In 2015, Indigenous and Northern Affairs Canada provided funding to Loon River First Nation, White Bear First Nation and Frog Lake First Nation, some of the top-producing First Nations, so they could obtain independent technical and legal reviews of the draft Regulations. This was done to complement and confirm similar reviews conducted by the Joint Technical Committee.

The draft Regulations were distributed three times as consultation drafts, in March 2014, in May 2015, and in September 2017 to different groups of stakeholders, including the Indian Resource Council, all oil- and gas-producing First Nations, other First Nation organizations, oil and gas companies, the Canadian Association of Petroleum Producers and provincial oil and gas regulators. An advance copy of the prepublication draft was provided at two symposiums held in early 2016 for Chiefs of oil- and gas-producing First Nations from British Columbia, Alberta and Saskatchewan. Approximately 150 attendees participated in these symposiums that saw the draft reviewed clause by clause. The May 2015, early 2016, and September 2017 versions were also published in the First Nations Gazette for public review and feedback.

Additional consultation activities were conducted during the 2016–17 winter and spring, which resulted in several changes to the draft regulations to accommodate oil- and gas-producing First Nations' desire for increased participation in the management of their oil and gas resources. These changes provide First Nations with additional flexibility in approving continuances, amending drilling commitments, and dealing with assignments.

Oil- and gas-producing First Nations and First Nations with oil and gas potential, the major oil- and gas-producing provinces, and the oil and gas industry all support the development of a modernized on-reserve oil and gas regime since they stand to benefit from an improved business climate as a result.

All feedback from different groups of stakeholders, including the Indian Resource Council, oil- and gas-producing First Nations, First Nations organizations, industry and provinces was carefully considered and has been invaluable in improving the proposed Regulations. Stakeholder feedback received was grouped under the following three themes: (1) technical; (2) First Nation governance; and (3) First Nation consultation.

Technical comments received include proposed changes to data requirements, time frames, and environmental protection measures. The comments received were accommodated in the proposed Regulations where appropriate.

While there is general support for the need for a modern regulatory regime, over the course of the legislative and regulatory development process, some First Nations raised broader jurisdictional aspirations related to management and control of their oil and gas resources. These aspirations were not at this point accommodated to the extent desired; the proposed Regulations intend to strike a balance between the flexibility that First Nations requested and the requirements of a modern regime that is more closely aligned with the regulatory environment off reserve.

However, in response to feedback related to First Nation governance and consultation, and the jurisdictional aspirations of First Nations, the Government of Canada has committed to explore, in partnership with oil and gas First Nations, potential options for greater First Nation jurisdiction and control over oil and gas management on reserve. The Government is actively engaging First Nations to determine how this objective may be attained with a view to bringing recommendations forward for consideration by the Government.

A record of consultation on the Act and its regulations was posted on the Indian Oil and Gas Canada website at http://www.pgic-iogc.gc.ca/eng/1471964522302/1471964567990. In addition, this proposal is published on the First Nations Gazette at http://www.fng.ca for public consultation.

Regulatory coordination and cooperation

This proposal would bring the federal regulatory regime for oil and gas development activities on First Nation reserve lands into greater alignment with provincial regulations and practices off reserve. The proposal would reduce duplication of processes and clarify procedures between on- and off-reserve projects, resulting in an expected net present value savings to industry of over $55.2 million, as well as increase consistency between on- and off-reserve compliance, enforcement and environmental regimes.

Rationale

The federal government has committed to support stronger Indigenous communities, economic development, appropriate regulatory oversight, and credible environmental assessments through the implementation of the modernized IOGA, 2009 and its associated regulations.

The federal government and First Nations stakeholders agree that a modern oil and gas regulatory regime on First Nation reserve lands would support sound development of these resources on reserve, while addressing the specific needs and contexts of First Nation communities. New legislation and regulations are considered the best option to provide clear authorities and powers for Canada; to remove barriers to investment on First Nation reserve lands through a closer alignment with provincial rules and practices; and to reduce the reliance on rules embedded in contracts so that Canada has the proper tools, equivalent to provincial regulators, to encourage industry compliance and to respond appropriately to address non-compliance.

Updating the on-reserve regulatory regime is anticipated to improve the business climate on oil and gas First Nation reserve lands and be beneficial to all stakeholders, including First Nations and industry. Stakeholders were extensively consulted and are in support of the proposed Regulations. No undue impacts on other areas or sectors are expected.

Implementation, enforcement and service standards

These Regulations would come into force upon registration.

Indian Oil and Gas Canada personnel are responsible for the administration and enforcement of the Act and its Regulations. Throughout the development of the proposed Regulations, Indian Oil and Gas Canada personnel have been preparing for implementation by developing or modifying forms, procedures and information systems and training personnel in order to implement and enforce the modernized regulatory regime proposed in these Regulations.

In addition, Indigenous and Northern Affairs Canada also funded the production of a First Nations Readiness Report, which was completed in March 2016. This report recommended areas where support should be provided to First Nations for the implementation of the proposed Regulations. Indigenous and Northern Affairs Canada is in discussions with the Indian Resource Council to determine the best approach for addressing First Nation readiness requirements.

It is anticipated that stakeholders will have the necessary information to comply with the Regulations and their new requirements when the Regulations will come into force. Furthermore, once the Regulations are registered, information packages about the modified, clarified and new requirements will be provided to all stakeholders. Information will also be provided on the Indian Oil and Gas Canada and Indigenous and Northern Affairs Canada websites. In practice, there is a high level of compliance in the area.

Indian Oil and Gas Canada will train staff and develop operational policies, including a process guide for industry, in order to efficiently and effectively implement the proposed administrative penalties system.

Contacts

For English inquiries:

John Dempsey
Director
Regulatory Compliance
Indian Oil and Gas Canada
9911 Chiila Boulevard, Suite 100
Tsuu T'ina (Sarcee), Alberta
T2W 6H6
Fax:
403-292-4864
Email:
John.Dempsey@canada.ca

For French inquiries:

Patrick Watson
Acting Director
Policy, Research and Legislative Initiatives
Indigenous and Northern Affairs Canada
10 Wellington Street, 17th Floor
Gatineau, Quebec
K1A 0H4
Fax:
819-994-4345
Email:
patrick.watson2@canada.ca

PROPOSED REGULATORY TEXT

Notice is given that the Governor in Council, pursuant to section 4.1 footnote a and subsection 21(1) footnote b of the Indian Oil and Gas Act footnote c, proposes to make the annexed Indian Oil and Gas Regulations.

Interested persons may make representations concerning the proposed Regulations within 90 days after the date of publication of this notice. All such representations must cite the Canada Gazette, Part I, and the date of publication of this notice, and be addressed to John Dempsey, Director, Regulatory Compliance, Indian Oil and Gas Canada (email: contactIOGC@aandc-aadnc.gc.ca).

Ottawa, May 10, 2018

Jurica Čapkun
Assistant Clerk of the Privy Council

Indian Oil and Gas Regulations

Interpretation

Definitions

1 (1) The following definitions apply in these Regulations.

Act means the Indian Oil and Gas Act. (Loi)

actual selling price means

adjoining, in relation to two spacing units, means touching at a common point, without regard to any road allowances between the spacing units. (adjacent)

bitumen means oil that does not flow from a reservoir to a well unless it is heated or diluted. (bitume)

exploration work includes mapping, surveying, examining geological, geophysical or geochemical data, test drilling and any other activities that are carried out by air, land or water and are related to the exploration for oil or gas. (travaux d'exploration)

First Nation spacing unit means a spacing unit in which 50% or more of the lands are First Nation lands that belong to the same First Nation. (unité d'espacement d'une première nation)

horizontal section means the portion of a wellbore that has

horizontal well means a well that has been approved as a horizontal well by the provincial authority or a well with a horizontal section that has been approved by the provincial authority. (puits horizontal)

off-reserve spacing unit means any spacing unit that is not a First Nation spacing unit. (unité d'espacement hors réserve)

offset period means the period established in accordance with subsection 93(4). (délai de compensation)

offset well means a well that is located in a First Nation spacing unit adjoining an off-reserve spacing unit in which a triggering well is located and that is producing from the same zone as the triggering well. (puits de limite)

offset zone means the zone from which a triggering well is producing. (couche de compensation)

pool means a natural underground reservoir that contains or appears to contain an accumulation of oil or gas that is separate or appears to be separate from any other such accumulation. (bassin)

prescribed means prescribed by the Minister under subsection 5(1) of the Act. (Version anglaise seulement)

productive means producing or capable of producing oil or gas in a quantity that would warrant incurring

project means a project or plan for the recovery of oil or gas, other than a bitumen recovery project, for which the approval of the provincial authority is required. (projet)

provincial authority means the office, department or body that is authorized by law to make decisions, grant approvals, receive information or keep records respecting the exploration for, or the exploitation or conservation of, oil and gas in the province in which the relevant First Nation lands are located. (autorité provinciale)

service well means a well that is operated for observation or for the injection, storage or disposal of fluids. (puits de service)

spacing unit means an area in a zone that is designated as a spacing unit, a spacing area, a drainage unit or other similar unit by the provincial authority. (unité d'espacement)

subsurface contract means a permit or subsurface lease granted under the Act. (contrat relatif au sous-sol)

surface contract means a surface lease or right-of-way granted under the Act. (contrat relatif au sol)

surface rates means the amounts, referred to in subsections 73(2) and (3), that are to be paid by a surface contract holder. (frais de surface)

triggering well means a well that is producing from one or more off-reserve spacing units adjoining a First Nation spacing unit. (puits déclencheur)

unit agreement means an agreement that combines the interests or rights of all the holders of oil and gas rights in all or part of a reservoir and provides for the joint exploitation of the oil and gas and the payment of royalties based on an allocation of production rather than actual production, but does not include an agreement that allocates production from a well referred to in subsection 107(1). (accord de mise en commun)

well means a well that is used for the exploitation of oil or gas and includes a vertical well, a deviated well and a horizontal well. (puits)

zone means a stratum of lands identified as a zone in accordance with the log data set out in Schedule 3 or 4, as the case may be. (couche)

Incorporation by reference

(2) A reference to a document that is incorporated by reference into these Regulations is a reference to the document as amended from time to time or, if the document no longer exists, to any successor to it that provides the same information.

General Rules

Notices, documents or information

2 (1) Any notice, document or information that is sent or submitted under these Regulations must be in paper or electronic form or published on the website of Petrinex or any successor to Petrinex.

Address for service

(2) Every holder of a contract must, in the prescribed form, provide the Minister with their address for service and send him or her a notice of any change to that address.

Deemed receipt — paper form

(3) Any notice, document or information that the Minister sends to a holder in paper form at their address for service is deemed to have been received by the holder on the fourth day after the day on which it is sent.

Deemed receipt — electronic form

(4) Any notice, document or information that the Minister sends to a holder in electronic form to their latest address for service or publishes on Petrinex is deemed to have been received by the holder on the day on which it is sent or published.

Record search

(5) A person may apply to the Minister for a record search of non-confidential, contractual documentation that is in the Minister's possession and stored in electronic form if the application is in the prescribed form and accompanied by the record search fee set out in Schedule 1.

Information

3 Despite any provision of these Regulations, a person is not obliged to submit information to the Minister that the Minister has advised is in his or her possession or is available to him or her from another source such as Petrinex.

Form not prescribed

4 When an application or other information is required by these Regulations to be submitted in a prescribed form, but no form has been prescribed, the application or information may be submitted in any form so long as it includes all the required information.

Alternative format

5 When a notice, a document or information is required by these Regulations to be submitted in a specified format, the person required to submit it may use an alternative format if the Minister advises that he or she has the capacity to read and use the information in that alternative format.

Eligibility

6 A person is eligible to be granted a contract if

Holder's responsibility

7 Every contract holder must ensure that any requirement that is related to their contract and is imposed by these Regulations on a person other than the holder is fulfilled.

Liability — holders and persons with working interest

8 (1) Every contract holder and person with a working interest in a contract is absolutely liable for any damage to the environment that is caused by operations carried out under the contract.

Liability — operators and licensees

(2) Every operator, well licensee, pipeline licensee and facility licensee is absolutely liable for any damage to the environment that is caused by operations they carry out under the contract.

Insurance required

9 (1) A contract holder must obtain, and maintain during the term of the contract, an insurance policy that is adequate to cover all risks resulting from the operations to be carried out under the contract.

Minimum coverage

(2) The insurance policy must provide the following minimum coverage:

Subrogation

(3) Every insurance policy obtained by the holder must provide that the insurer's right of subrogation is waived in favour of the Minister.

Notice of cancellation

(4) The holder must, without delay, send the Minister notice if any coverage under their insurance policy is terminated and at least 30 days before the last day of coverage if the holder intends to cancel any of their coverage.

Maximum deductible

(5) The deductible of every insurance policy must not exceed 5% of the amount of insurance.

Self-insurance

10 A holder may fulfil the obligation imposed by subsection 9(1) by providing the Minister with a letter of self-insurance in the prescribed form in which the holder

Contractors' insurance

11 A contract holder must ensure that any person that carries out operations under the contract, other than an employee, obtains and maintains an insurance policy that is adequate to cover all risks resulting from those operations.

Contract area boundaries

12 (1) The boundaries of a contract area must correspond to the boundaries of the legal land divisions of the relevant province if the lands in the contract area have been surveyed or to the anticipated boundaries of those divisions if the lands have not been surveyed.

Unsurveyed lands

(2) If the lands in a contract area are surveyed during the term of the contract, the Minister must, after consulting with the holder and the council, amend the contract so that the description of the lands complies with subsection (1).

Exception

(3) Subsections (1) and (2) do not apply if the contract area is in a reserve whose configuration prevents compliance with those subsections.

Survey plans

13 (1) Every survey plan that is required under these Regulations must be

Exception

(2) Subsection (1) does not apply to

Dispute

14 If a dispute arises regarding the location of a well, facility or boundary referred to in a contract, the Minister may order the holder to have a survey conducted as soon as the circumstances permit.

Annual meeting request

15 (1) A council whose First Nation lands are subject to a contract may, no more than once a year, submit a request to the Minister in the prescribed form for a meeting with the holder for the purpose of discussing the operations that have been carried out, or are planned to be carried out, in the contract area.

Minister's notice

(2) The Minister must send the holder notice of a meeting request.

Arrangement of meeting

(3) The holder must organize the meeting and ensure that it takes place within 90 days after the day on which the Minister's notice is received. In the case of multiple holders, they may designate one of their number to attend as their representative.

Multiple contracts

(4) If the holder has more than one contract in the First Nation lands, operations carried out under all the contracts may be discussed at the same meeting.

Expenses

(5) Any expense relating to the request for, preparation for or attendance at a meeting must be borne by the party that incurs the expense.

Unforeseen incident

16 An operator must, in the most expeditious manner possible, send the Minister and the council notice of any unforeseen incident that occurs during operations carried out under a contract and that results in, or could result in, bodily injury, death or damage to First Nation lands or property. The operator must report the details of the incident, in the prescribed form, as soon as the circumstances permit.

Person accompanying inspector

17 For the purpose of monitoring compliance with the Act and these Regulations, a person may accompany an inspector who is inspecting a holder's facilities and operations on First Nation lands if the person is authorized to do so by a written resolution of the council and has the certifications and complies with the occupational health and safety requirements required or imposed by the holder or by law.

Payment of rent

18 (1) Any annual rent that is payable under a contract must be paid on or before the anniversary of the effective date of the contract.

Refund

(2) Any rent that is owed for the year in which a contract ends must be paid and is not refundable. However, any rent that has been paid for a subsequent year must be refunded.

Exception

(3) Subsection (1) does not apply to a contract that was granted before the day on which these Regulations came into force and provides otherwise.

Payment to Receiver General

19 (1) All money that is owed to Her Majesty under these Regulations or a contract must be paid to the Receiver General for Canada.

Purpose of payment

(2) The money must be accompanied by a statement, in the prescribed form, indicating the purpose for which it is made.

Amendments

20 (1) Any amendment to a contract or a bitumen recovery project requires the prior approval of the council as well as the Minister.

Limits

(2) The Minister must not approve an amendment unless

Exception

(3) Subsection (1) does not apply to an amendment referred to in subsection 12(2) or to one that reduces the area of lands subject to a subsurface contract or a bitumen recovery project.

Well data

21 An operator that carries out operations in connection with a well must submit the following documents and information to the Minister and the council within the following time limits:

Additional information

22 The operator must also submit to the Minister and the council any additional technical information about the well that is necessary to determine its productivity.

Information in reports

23 (1) Any information that is submitted to the Minister or a council under the Act must be kept confidential until the end of the period in which such information must be kept confidential under the law of the relevant province, unless the person that submitted it consents in writing to its disclosure.

Seismic data

(2) Despite subsection (1), seismic data submitted by the holder of an exploration licence under paragraph 33(3)(a) may be disclosed by the Minister or the council on the earlier of

Interpretation

(3) Any interpretation of seismic data, including maps, that is submitted to the Minister or a council under the Act may be disclosed only if the person that submitted it consents in writing to its disclosure.

Disclosure to council

(4) Despite subsections (1) to (3), the Minister may at any time disclose

Incorrect information

24 A person that submits information to the Minister and becomes aware that it is incorrect must submit the correct information to the Minister as soon as the circumstances permit.

Approval of assignment

25 (1) Any assignment of any of the rights conferred by a contract must be approved by the Minister. The application for approval must be in the prescribed form and be accompanied by the fee for an assignment approval application set out in Schedule 1.

Copy to council

(2) The applicant must send the council a copy of the application for approval on or before the day on which the application is submitted to the Minister.

Delayed decision

(3) The Minister must not decide whether to approve the assignment during the 15 days after the day on which the application for approval was received.

Meeting request

(4) During the 15-day period, the assignee must meet with the council at its request. The meeting must be face to face unless the parties agree to another mode of meeting.

Expenses

(5) Any expense relating to the request for, preparation for or attendance at a meeting must be borne by the party that incurs the expense.

Refusal to approve

(6) The Minister must not approve the assignment if

Minister's decision

(7) If the Minister approves the assignment and signs it, he or she must send a copy to the assignor and assignee and a notice of the approval to the council.

Effective date

(8) The assignment takes effect on the day on which the Minister approves it unless the it provides for a different effective day.

Joint and several liability

26 (1) If the assignment is approved, the assignor and assignee are jointly and severally, or solidarily, liable for any obligation owing and any liability arising under the contract before the day on which it was approved, even if the contract is subsequently assigned.

Exception

(2) Subsection (1) does not apply to an assignment that was approved before the coming into force of these Regulations.

Terms To Be Included in Every Contract

Compliance with laws

27 (1) Every contract granted by the Minister under these Regulations includes the holder's undertaking to comply with

Conflict resolution

(2) The provisions of any Act, regulation or order incorporated into a contract under subsection (1) prevail over any other terms of the contract, except for any terms respecting royalties negotiated under subsection 4(2) of the Act, to the extent of any inconsistency. The provisions of any federal Act, regulation or order incorporated into a contract under subsection (1) prevail over the laws of the province that are incorporated to the extent of any inconsistency.

Inconsistency

(3) For the purposes of this section, provisions — whether legislative or contractual — are not inconsistent unless it is impossible for the holder to comply with both.

Exploration

Authorization

Authorization to explore

28 A person may carry out exploration work on First Nation lands if they

Application for Exploration Licence

Preliminary negotiation

29 (1) Before applying for an exploration licence, an applicant and the council must agree on the location of the proposed seismic lines and on the seismic rates, if those rates have not already been fixed in a related subsurface contract.

Application for licence

(2) The application must be submitted to the Minister in the prescribed form and include

Environmental review

(3) The results of the environmental review must be submitted in the prescribed form and include

Environmental protection measures

(4) If the exploration program can be carried out without causing irremediable damage to the First Nation lands, the Minister must send the application to the applicant and the council, along with a letter that sets out the environmental protection measures that must be implemented to permit the holder to carry out its exploration program.

Council approval

(5) To obtain the exploration licence, the applicant must, within 90 days after the day on which the reviewed application is received, submit to the Minister three copies of the environmental protection measures letter and three original copies of the application signed by the applicant, along with a written resolution of the council approving the licence.

Exploration licence

(6) If the requirements set out in this section are met, the Minister must grant the exploration licence for a period of one year. The terms of the licence are those set out in the application and the environmental protection measures letter. The licence takes effect on the day on which it is signed by the Minister.

Operations Under Exploration Licence

Exploration and subsurface rights

30 An exploration licence holder may exercise the rights conferred by the licence in an area that is subject to a subsurface contract, but in doing so must not interfere with any operations carried out under the subsurface contract.

Priority

31 Every exploration licence is subject to

Maximum drilling depth

32 (1) The holder of an exploration licence must not drill to a depth of more than 50 m, unless authorized to do so by their licence.

Holder's obligations

(2) The holder must

Exploration report

33 (1) The holder of an exploration licence must submit an exploration report to the Minister within 90 days after the day on which the exploration work is completed.

Content of exploration report

(2) The report must comply with any exploration reporting requirements of the relevant province and must include, in addition to the documents and information referred to in paragraph 32(2)(f),

Content of geophysical report

(3) The geophysical report must include

Exception

(4) The holder may include maps at contour line intervals or scales other than those specified in subsections (2) and (3) if the alternative intervals or scales would enhance the interpretability of the maps.

Information available to council

(5) The Minister must make the information submitted under subsections (2) to (4) available to the council.

Information to be kept

(6) In addition to the information submitted under this section, the holder must keep any information that was obtained as a result of the exploration work carried out in the contract area, including any paper or magnetic digital display of raw or interpreted seismic data, and must make it available for review by the Minister at their office during business hours after the later of

Remediation and reclamation

34 When exploration work under an exploration licence is no longer being carried out, whether or not the licence has ended, the holder must ensure that all the lands on which the work was carried out are remediated and reclaimed.

Subsurface Rights

Grants of Subsurface Rights

General Rules
Subsurface contracts

35 (1) Oil and gas rights in First Nation lands may be granted by the Minister under one of the following subsurface contracts:

Process

(2) A subsurface contract must be granted in accordance with the public tender process set out in sections 39 to 42 or the negotiation process set out in sections 44 to 46, as chosen by the council. The negotiation process may be preceded by a call for proposals in accordance with section 43.

No splitting of rights

(3) When granting a subsurface contract, the Minister must grant all the rights to the oil and gas in each zone included in the contract area.

Priority

36 A subsurface contract holder's rights are subject to the right of an exploration licence holder to carry out exploration work in, and the right of any other subsurface contract holder to work through, the subsurface contract area.

Multiple holders

37 (1) A subsurface contract may be granted to no more than five persons, each having an undivided right or interest in the contract of at least 1%. The interest must be expressed in decimal form to no more than seven decimal places.

Joint and several liability

(2) If two or more persons have an undivided interest or right in a subsurface contract, they are jointly and severally or solidarily liable for all obligations under the contract, the Act and these Regulations.

Determination of fair value

38 In determining the fair value of the interests or rights to be granted under a subsurface contract, the Minister must, in consultation with the council, consider the bonuses paid for grants of oil and gas rights in other lands, which may be adjusted to take into account the following factors:

Public Tender Process
Public tender

39 The Minister may grant the oil and gas rights in First Nation lands by way of public tender only if the council requests or consents to that process.

Minister's duties

40 (1) When oil and gas rights are to be granted by way of public tender, the Minister must, after consulting with the council, prepare a notice of tender.

Notice of tender

(2) The notice of tender must include the following information:

Publication of notice of tender

(3) The Minister must submit a copy of the proposed notice of tender to the council before publishing it and, if it is approved, must publish it

Submission of bids

41 (1) All bids must be submitted in accordance with the instructions set out in the notice of tender, be sealed and include

Certified funds

(2) The fee, rent and bonus must be paid in certified funds unless the notice specifies a different form of payment.

Opening of bids

42 (1) After the tender closes, the Minister must without delay open the bids, exclude any bids that were not submitted in accordance with section 41, identify the bid with the highest bonus and send the council notice of that bid.

Presence at opening

(2) The council or a person designated by the council may be present when the Minister opens the bids.

Tied bid

(3) If the highest bonus is contained in more than one bid, the Minister must republish the notice of tender.

Council's decision

(4) The council may, within seven days after the day on which the tender closes, notify the Minister by written resolution that it rejects the bid with the highest bonus. If such a notice is received, all bids must be rejected.

Irrevocable decision

(5) If a council notifies the Minister that it approves the bid with the highest bonus, that bid cannot later be rejected under subsection (4).

Acceptance of highest bid

(6) If a notice rejecting the bid is not received, the Minister must accept it and send the winning bidder a notice of acceptance. The contract takes effect on the day on which the tender closed.

Posting of tender results

(7) The Minister must publish the name of the winner and the winning bonus amount or, if no bid was accepted, a notice to that effect, in the publication or on the website where the notice of tender was published.

Confidentiality

(8) Except for the name of the winning bidder and bonus amount, the information in bids must be kept confidential.

Contract granted

(9) The Minister must prepare the subsurface contract and send a copy to the council and the winning bidder.

Unsuccessful bids

(10) The Minister must return the fee, rent and bonus included in each unsuccessful bid to the person that submitted it.

Call for Proposals Process
Call for proposals

43 For the purpose of soliciting interest in rights in First Nation lands, either the council, or the Minister jointly with the council, may make a call for proposals. The call may be made by public notice or by other means and must include the following information:

Negotiation Process
Application

44 (1) A person may apply to the Minister for a subsurface contract that confers oil and gas rights in one or more zones in First Nation lands.

Preliminary negotiation

(2) Before applying for a subsurface contract, an applicant and the council must agree on the following terms:

Application for contract

(3) The application to the Minister must be in the prescribed form, set out the terms negotiated by the applicant and the council and be accompanied by the subsurface contract application fee set out in Schedule 1.

Confidentiality

(4) Any information that is disclosed during the negotiations referred to in subsection (2) or in an application referred to in subsection (3) must be kept confidential.

Conditions of approval

45 (1) The Minister must not approve the application unless

Approval of application

(2) If the application is approved, the Minister must prepare the subsurface contract and send a copy to the council and the applicant. The Minister must fix and include in the contract the surface rates to be paid under any related surface contract and the seismic rates to be paid under any related exploration licence.

Criteria — rates

(3) The surface rates must be fixed in accordance with subsections 73(2) and (3). The seismic rates must be comparable to seismic rates for exploration on lands, excluding provincial Crown lands, that are similar in size, character and use.

Refusal of application

(4) If the application is not approved, the Minister must send the applicant and council a notice of refusal that sets out the reasons for the refusal.

Granting of contract

46 (1) The Minister must grant the contract if he or she receives the following within 90 days after the day on which a copy of the contract has been received by both the council and the applicant:

Effective date

(2) The contract takes effect on the day on which it is granted, unless it provides otherwise.

Terms of Subsurface Contracts
Subsurface contract rights

47 The holder of a subsurface contract has the exclusive right to exploit the oil and gas in the lands in the contract area and to process and dispose of that oil and gas.

Initial term of permit

48 (1) If the lands in a permit area are located in a province set out in column 1 of the table to Schedule 2, and in a region set out in column 2, the initial term of the permit is the term set out in column 3. Otherwise, the initial term is five years.

More than one region

(2) If the lands in a permit area are located in more than one region set out in column 2 of the table to Schedule 2, the initial term is the term for the region in which the greatest portion of the lands is located. If the portion of lands in each region is the same, the initial term is the longer of the terms set out in column 3.

Intermediate term of permit

(3) The intermediate term of a permit is three years.

Term of lease

49 The term of an oil and gas lease is three years.

Term — exception

50 (1) Despite subsections 48(1) and (2) and section 49, if the council and the applicant have agreed, the Minister may fix the initial term of a permit or the term of a lease at a number of years greater than the number established by those provisions, to a maximum of five years.

Amended term

(2) With the consent of the holder, the term of a subsurface contract may be amended, in accordance with subsection 20(1), to a maximum of five years.

Annual rent

51 The annual rent for a subsurface contract is $5 per hectare or $100, whichever is greater.

Selection of Lands for Intermediate Term of Permit
Lands earned

52 (1) A permit holder earns lands, and may select from those lands for the intermediate term of the permit if during the initial term they have, in accordance with the earning provisions of their permit,

Failure to comply with earning provisions

(2) If a holder fails to meet a deadline set out in an earning provision of their permit, the permit terminates on the day of the deadline with respect to all lands that have not been earned on or before that day.

Selection of lands

(3) A holder that has earned lands may select from those lands down to the base of the deepest zone into which they have drilled, identified in accordance with Schedule 3.

Constraints on selection

(4) The lands selected under subsection (3) must

Interests or rights less than 75%

53 (1) A holder that has drilled a well in a spacing unit in which the First Nation interests or rights are less than 75% may only select lands in the section in which the well is located down to the base of the deepest zone into which they have drilled.

Reduced earnings — new well

(2) A holder that has drilled a new well, but has not drilled to the extent required by the earning provisions of their permit, may select lands in the section in which the well is located down to the base of the deepest zone into which they have drilled.

Reduced earnings — re-entered well

(3) A holder that has re-entered and completed a well, but has not drilled to the extent required by paragraph 52(1)(b) and the earning provisions of their permit, may select the lands in the spacing unit in which the well is completed.

Application

54 (1) A holder that wants a grant of the oil and gas rights for the intermediate term of their permit must apply to the Minister for approval of their selection of lands before the day on which the initial term of the permit expires, but

Late application

(2) A holder that fails to apply within the relevant deadline referred to in subsection (1) may apply for approval if the application is submitted within 15 days after the day of the deadline and is accompanied by a late application fee of $5 000.

Content of application

(3) The application must be in the prescribed form and include

Additional information

(4) Information about a well that is drilled, or re-entered and completed, within 30 days before the relevant deadline may be submitted up to 15 days after that deadline, unless the holder has received an extension under subsection 62(2).

Approval

(5) On receiving an application, the Minister must

Notice to holder and council

(6) If the selection is approved and the oil and gas rights are granted, the Minister must send the holder and the council a notice of the approval and a description of the lands, including the zones, selected for the intermediate term of the permit. If the selection is not approved, the Minister must send the holder a notice of refusal that sets out the reasons for the refusal.

Transitional provision

55 Sections 47 to 54 do not apply to a contract that was granted under the Indian Oil and Gas Regulations, 1995.

Bitumen Recovery Project Approval
Application for approval

56 (1) A subsurface contract holder may apply to the Minister for approval of a bitumen recovery project if they have achieved the minimum level of evaluation and have applied to the provincial authority for approval of the project.

Minimum level of evaluation

(2) The minimum level of evaluation is achieved when

Content of application

57 (1) An application for approval of a bitumen recovery project must be in the prescribed form and include

Environmental review

(2) The results of the environmental review of the bitumen recovery project must be submitted in the prescribed form and include

Environmental protection measures letter

(3) After reviewing the application, the Minister must send the applicant and the council a letter that sets out the environmental protection measures that must be implemented to permit the holder to carry out operations under the project.

Approval

58 (1) The Minister must approve the bitumen recovery project if

Terms of approval

(2) The approval may include any terms that are necessary to permit the Minister to verify the progress of operations carried out under the project, payment of the approved royalty and implementation and compliance with the environmental protection measures.

Surface contract required

59 (1) The operations under a bitumen recovery project must not begin until the subsurface contract holder has obtained the surface contracts required by these Regulations.

Compliance with measures

(2) The holder must ensure that all environmental protection measures included in the approval are implemented and complied with.

Minimum level of production

60 (1) The minimum level of oil production per year required from lands that are subject to a bitumen recovery project is equal to an average of 2 400 m3 per section in the project area.

Compensation — bitumen

(2) A holder that fails to achieve the minimum level of production in any year following the month in which that level was to be achieved must pay compensation equal to 25% of the difference between the value of the minimum level of production and the value of the actual level.

Deemed price

(3) For the purpose of calculating the compensation, the price of oil is deemed to be the monthly Bitumen Floor Price published by the Alberta provincial authority for the relevant time period.

Exception

(4) This section does not apply to a project authorized by the Executive Director under section 42 of the Indian Oil and Gas Regulations, 1995.

Additional wells, lands or facilities

61 Once a bitumen recovery project has been approved, the subsurface contract holder must obtain the approval of the Minister and the council before adding lands, wells or facilities to the project.

Drilling Over Expiry
Application for extension

62 (1) A subsurface contract holder may apply to the Minister, in the prescribed form, for an extension of the deadline for submitting their application for approval of a selection of lands under subsection 54(1) or for continuation under section 64 if

Approval of extension

(2) If an application is submitted in accordance with subsection (1), the Minister must extend the deadline for applying for approval of a selection of lands or for continuation to the 30th day after the day on which the spudded or re-entered well is rig-released. The Minister must send the council a notice of the extension.

No additional wells

(3) During an extension, the holder may continue to produce from any existing wells in the contract area, but must not spud, or re-enter and complete, any additional wells in that area.

Transitional provision

(4) This section applies to a permit or lease granted under the Indian Oil and Gas Regulations, 1995.

Continuation of Subsurface Contracts
Qualifying lands

63 (1) A subsurface contract may be continued with respect to the zones, identified in accordance with Schedule 4, that are in a spacing unit

Horizontal and deviated wells

(2) For the purposes of subsection (1), each spacing unit from which a horizontal well or deviated well is productive is deemed to contain a productive well.

Potentially productive

(3) For the purpose of paragraph (1)(g), a spacing unit is potentially productive if

Application for continuation

64 (1) An application for the continuation of a subsurface contract may be made to the Minister before the day on which the lease or the intermediate term of the permit expires.

Content of application

(2) The application must be in the prescribed form and include

Determination

65 (1) On receiving an application for continuation, the Minister must determine which lands described in the application are in a spacing unit referred to in any of paragraphs 63(1)(a) to (f) and must continue the contract with respect to those lands.

Non-producing spacing unit

(2) If a non-producing spacing unit referred to in paragraph 63(1)(f) is smaller than one legal subdivision in the case of oil and one quarter-section in the case of gas, the Minister must continue the contract with respect to all the lands in the legal subdivision or quarter-section in which the spacing unit is located.

Potentially productive spacing unit

(3) If the Minister determines that lands described in the application are in a spacing unit referred to in paragraph 63(1)(g), he or she must send the holder an offer to continue the contract with respect to those lands.

Continuation

(4) The Minister must continue the contract with respect to lands in a spacing unit referred to in paragraph 63(1)(g) if, within 30 days after the day on which the offer of continuation is received, the holder pays the Minister a bonus equal to the greater of

Notice to holder and council

(5) The Minister must send the holder and the council a notice of his or her determination and — if the contract is continued — a description of the lands, including the zones, with respect to which it is continued as well as the basis for continuation.

Production before determination

(6) Before notice of the Minister's determination is received, the holder may continue producing from existing wells in the contract area, but must not spud, or re-enter and complete, any additional wells in that area.

Refund

(7) If the contract is not continued, the Minister must refund the rent submitted with the application. If the contract is continued only in part, the Minister must refund the rent for the lands with respect to which the contract is not continued.

Continuation requested by council

66 (1) The Minister may continue, for a maximum period of five years, a contract in respect of lands for which continuation was not granted under subsection 65(1) if

Council requested continuation — potentially productive spacing unit

(2) The Minister may continue, for a maximum period of five years, a contract continued under subsection 65(4) if

Additional bonus

(3) If the Minister determines that an additional bonus must be paid to reflect the fair value, determined in accordance with section 38, of the interests or rights to be continued, the Minister must not continue the contract unless that additional bonus is paid;

Failure to apply for continuation

67 (1) If a holder has not applied for continuation before the deadline referred to in subsection 64(1), the Minister must determine, as soon as the circumstances permit and on the basis of the information in his or her possession, whether their contract is eligible for continuation under any of paragraphs 63(1)(a) to (e).

Notice of eligibility

(2) If the contract is eligible for continuation, the Minister must send the holder a notice that includes the following information:

Application

(3) A holder that has received a notice of eligibility may, within 30 days after the day on which the notice is received, apply to the Minister, in the prescribed form, for continuation of the contract with respect to any of the lands described in the notice.

Content of application

(4) The application must include a description of the lands, including the zones, with respect to which continuation is sought, the rent for the first year of the continuation and a late application fee of $5 000.

Continuation to be granted

(5) If the holder pays the required rent and fee, the Minister must continue the contract with respect to the lands described in the application and send the council and the holder a notice of the continuation that describes the lands, including the zones, with respect to which it is continued as well as the basis for continuation.

Indefinite continuation

68 (1) A contract that is continued on the basis of any of paragraphs 63(1)(a) to (f) continues so long as the lands that are subject to the contract continue to be eligible on that basis or until the contract in respect of those lands is surrendered or cancelled.

Continuation for a year

(2) A contract that is continued under subsection 65(4) continues for a period of one year after the day on which the contract would have expired had it not been continued.

Non-productivity — oil and gas

69 (1) If a contract that is continued in respect of lands on the basis of paragraph 63(1)(a), (b), (d), (e) or (f) ceases to be eligible for continuation on that basis, the Minister must send the holder a notice of non-productivity that describes those lands and indicates the basis on which the contract has ceased to be eligible.

Non-productivity — expiry

(2) A contract referred to in subsection (1) expires with respect to the lands described in the notice of non-productivity one year after the day on which the notice is received.

Non-productivity — continuation

(3) Before the expiry of a contract with respect to lands described in a non-productivity notice, the holder may apply under section 64 to have the contract continued with respect to those lands on the basis of any of paragraphs 63(1)(a) to (f) other than the basis mentioned in the notice.

Application for continuation

(4) Before the expiry of a contract continued under subsection 65(4) or under section 66, the holder may apply under section 64 to have the contract continued on the basis of any of paragraphs 63(1)(a) to (f).

Inadequate productivity — bitumen

70 (1) In the case of a contract continued under paragraph 63(1)(c), if the annual minimum level of production from the lands that are subject to the bitumen recovery project is not achieved in any three years, whether or not the years are consecutive, the Minister must send the holder a notice of inadequate productivity with respect to those lands.

Termination and expiry

(2) If the minimum level of production from the lands that are subject to the bitumen recovery project is not achieved in any year following the day on which the notice of inadequate productivity is received,

Minister's determination

(3) When the Minister becomes aware that the minimum level of production from the lands that are subject to a bitumen recovery project will not be achieved in a year and the contract may expire under paragraph (2)(b), he or she must determine, as soon as the circumstances permit and on the basis of the information in his or her possession, whether the contract is eligible for continuation under any of paragraphs 63(1)(a), (b), (d) or (e) and, if so, must continue the contract on that basis.

Transitional provision — continuation

71 (1) Sections 63 to 68 apply to the continuation of any subsurface lease that was granted under the Indian Act or the Act before these Regulations came into force.

Transitional provision — non-productivity

(2) Section 69 applies to a subsurface lease that has been continued under the Indian Act or the Act before these Regulations came into force if the lands in the lease cease to be eligible for continuation on the basis on which they were continued.

Transitional provision — inadequate productivity

(3) Section 70 does not apply to a project that was authorized by the Executive Director under section 42 of the Indian Oil and Gas Regulations, 1995.

Surface Rights
Authorization

72 (1) A person may carry out surface operations on First Nation lands for the purpose of exploiting oil and gas if

Entry with permission

(2) A person that intends to apply for a surface contract in respect of First Nation lands to carry out operations referred to in subsection (1) may, with the permission of the council and any First Nation member in lawful possession of those lands, enter on the lands to locate proposed facilities, conduct surveys and carry out any operation necessary to complete an application under section 75.

Preliminary negotiation

73 (1) Before applying for a surface contract, the applicant must provide the council, and any First Nation member in lawful possession of lands in the proposed contract area, with a survey sketch of that area and must reach an agreement with them on the following:

Surface rates — right-of-way

(2) In the case of a right-of-way, the surface rates consist of

Surface rates — surface lease

(3) In the case of a surface lease, the surface rates consist of

Negotiation breakdown

74 If agreement cannot be reached on the amount of the initial compensation or annual rent to be paid, the Minister must, at the request of the applicant, the council or a First Nation member in lawful possession of lands in the contract area, determine the amount in accordance with subsection 73(2) or (3).

Application for contract

75 (1) The application for a surface contract must be submitted to the Minister in the prescribed form and include

Environmental review

(2) The results of the environmental review must be submitted in the prescribed form and include

Environmental protection measures

(3) If the application meets the requirements of subsection (1) and the proposed operations can be carried out without causing irremediable damage to the First Nation lands, the Minister must send the applicant and the First Nation a copy of the contract that includes

Submission to Minister

(4) The Minister must grant the contract if he or she receives the following:

Compliance with measures

(5) The holder must ensure that all environmental protection measures included in the contract are implemented and complied with.

Term

76 A surface contract ends on the day on which its surrender has been approved by the Minister, unless the contract provides otherwise.

Renegotiation of rent

77 (1) Unless a surface lease provides otherwise, the holder must renegotiate the amount of the rent with the Minister, the council and any First Nation member in lawful possession of lands in the lease area at the end of the shorter of

Lease to be amended

(2) The Minister must amend the lease to reflect the rent renegotiated under subsection (1) if

Renegotiation breakdown

(3) If agreement cannot be reached in renegotiating the rent, the Minister must, at the request of the holder, the council or any First Nation member in lawful possession of lands in the lease area, determine the rent, on the basis of the criteria mentioned in paragraph 73(3)(c), and the Minister must amend the lease accordingly.

Abandonment, remediation and reclamation

78 If the lands in a surface contract area are no longer used for the uses for which the contract was granted, the holder must abandon any well and facilities in the area and remediate and reclaim all lands in the area. The holder's obligations under the contract do not end until those operations are completed.

Royalties
Payment of royalty

79 (1) Except as otherwise provided in a special agreement entered into under subsection 4(2) of the Act, a subsurface contract holder must pay a royalty, in an amount calculated in accordance with Schedule 5, on the oil and gas produced from or attributable to the subsurface contract area.

Index price or actual selling price

(2) If a special agreement entered into under subsection 4(2) of the Act provides that the royalty on oil or gas is to be calculated using a monthly index price rather than the actual selling price, the holder must, in the prescribed form, provide the Minister with the index price for each month in which the oil or gas is produced.

Deadline for payment

80 The royalty must be paid on or before the 25th day of the third month after the month in which the oil or gas is produced.

Royalty — every sale

81 (1) Subject to subsection (2), every sale of oil or gas that is obtained from, or attributable to, a subsurface contract area must include the sale on behalf of Her Majesty in right of Canada of any oil or gas that constitutes the royalty payable under the Act.

Payment in kind

(2) After giving the holder notice, and having regard to any obligations that the holder may have in respect of the sale of oil or gas, the Minister may, with the prior approval of the council, direct the holder to pay all or part of the royalty in kind for a specified period or until the Minister directs otherwise.

Information to be kept

82 (1) Every person that produces, sells, acquires or stores oil or gas that has been obtained from First Nation lands, or acquires a right to such oil or gas, must keep, for a period of 10 years, all information that may be used to calculate the royalty owing in respect of that oil and gas, including any information required by this section.

Information — royalties

(2) Every person referred to in subsection (1) must submit the following information to the Minister in the prescribed form as soon as it becomes available:

Information — related parties

(3) The Minister may require a person referred to in subsection (1) to submit information for the purpose of determining whether the parties to a transaction are related.

Related parties

(4) Persons are related parties for the purpose of subsection (3) if they are considered to be related persons within the meaning of section 251 of the Income Tax Act.

Order to submit plans or diagrams

83 (1) For the purpose of verifying the royalty payable under a contract, the Minister may order an operator to submit a plan or diagram, drawn to a specified scale, of any facility that is used by the operator in exploiting oil or gas.

Deadline

(2) An operator that receives an order must submit the requested plan or diagram within 30 days after the day on which the order is received.

Notice to submit documents

84 (1) For the purpose of verifying the royalty payable under a contract, the Minister may send a notice requiring any person that has sold, purchased or swapped oil or gas obtained from First Nation lands to provide any of the following documents:

Deadline

(2) A person that receives a notice sent under subsection (1) must submit the requested documents within 14 days after the day on which the notice is received.

First Nation Audits and Examinations

General Rules
Agreement required

85 (1) A First Nation may conduct an audit or examination for the purpose of verifying the royalties payable on oil or gas obtained from its lands if

Procedure to obtain agreement

(2) A council that has obtained preliminary approval of a proposed audit or examination under section 89 may request that the Minister enter into an audit or examination agreement under section 90.

Qualifications

86 (1) A person who conducts an audit or examination under the Act must have the credentials and experience required to carry out their role in the audit or examination in accordance with generally accepted auditing practices.

Requirements

(2) A person who conducts an audit or examination under the Act, or accompanies an auditor or examiner,

Confidentiality — First Nation

87 (1) A First Nation that conducts an audit or examination must keep confidential any documents or information it obtains in connection with the audit or examination and must comply with the security requirements imposed by the holder of the contract or by law.

Exception

(2) Despite subsection (1), the council must provide the Minister with a copy of all audit or examination reports and working papers within 30 days after the day on which the audit or examination is completed.

Preliminary Approval
Application — preliminary approval

88 To obtain preliminary approval of a proposed audit or examination, a council must apply to the Minister in the prescribed form. The application must include

Decision

89 (1) The Minister must give preliminary approval if the requirements of section 88 are met, except in the following circumstances:

Notice of decision

(2) The Minister must give the council notice of his or her decision and, if preliminary approval is refused, the reasons for the refusal.

Request for Agreement
Request for agreement

90 A council's request for an audit or examination agreement must be made to the Minister in the prescribed form within 180 days after the day on which the notice of preliminary approval is received and include the following:

Refusal

91 The Minister may refuse the request if

Agreement

92 If the request is accepted, the Minister must enter into an agreement with the council that includes the information referred to in paragraphs 88(a) to (d) and 90(a) to (d).

Equitable Production of Oil and Gas

Holder's Obligations
Compensatory royalty

93 (1) The holder of a subsurface contract is obliged to pay Her Majesty in right of Canada, in trust for the relevant First Nation, a compensatory royalty in respect of each triggering well that is located in an off-reserve spacing unit that adjoins a First Nation spacing unit that is in their contract area.

Royalty for each spacing unit

(2) A compensatory royalty must be paid in respect of each First Nation spacing unit in the contract area that adjoins the spacing unit in which the triggering well is located.

Beginning of obligation

(3) The obligation to pay the compensatory royalty begins on the first day of the month that follows the day on which the offset period ends.

Offset period

(4) The offset period begins on the day on which an offset notice is received and ends on

Offset Notice
Offset notice

94 (1) If the Minister becomes aware that a triggering well is in production, the Minister must send an offset notice to every subsurface contract holder that is obliged to pay a compensatory royalty under section 93.

Confidential information

(2) However, if information about a well in respect of which a notice must be sent is confidential under the law of the relevant province, the Minister must send the notice only when he or she becomes aware that the information has been made public.

Absence of contract

(3) If any lands in a First Nation spacing unit that adjoins a spacing unit from which a triggering well is producing are not subject to a subsurface contract, the Minister must

Information included in notice

95 (1) The offset notice must include the following information:

Notice to council

(2) The Minister must send the council a copy of the offset notice and, when the offset period ends, a notice indicating that the holder's obligation to pay a compensatory royalty has begun.

No obligation

96 (1) The obligation to pay a compensatory royalty does not begin if, during the offset period, the subsurface contract holder submits to the Minister information that establishes any of the following circumstances:

Notice to holder

(2) After determining whether a circumstance referred to in subsection (1) has been established, the Minister must send the holder a notice of his or her determination.

Surrender

(3) A holder is not obliged to pay a compensatory royalty if, during the offset period, they surrender their rights down to the base of the offset zone in the spacing unit to which the offset notice applies, except for any rights in a zone from which a well is productive or that is subject to a unit agreement or to a storage agreement that has been approved by the provincial authority.

Notice to council

(4) If the obligation to pay a compensatory royalty ends, the Minister must send the council a notice indicating that it has ended and the reasons why it has ended.

Calculation and Payment of Compensatory Royalty
Royalty formula

97 (1) The compensatory royalty that is payable for a month is

(L⁄T) × 100

where

First Nation interest

(2) If the First Nation to which a compensatory royalty is payable has an interest or right in the spacing unit in which the triggering well is located, the compensatory royalty payable for a month is an amount prorated in accordance with the formula

C × (100 − I)⁄100

where

Calculation of compensatory royalty

(3) For the purpose of calculating the compensatory royalty for a month,

Heating value

(4) If the royalty calculation requires the conversion of a price in $/GJ into a price in $/103m3, the heating value is 37.7 GJ/103m3.

No deduction

(5) No deduction for costs or allowances is to be made in the calculation of the compensatory royalty.

Transitional provision

(6) This section does not apply to a compensatory royalty that is owed under the Indian Oil and Gas Regulations, 1995.

Calculation and payment of royalty

98 On or before the 25th day of the third month after the month in which the oil or gas is produced from the triggering well, the holder must pay the Minister the royalty for that month and, in the prescribed form, provide the information that is required to verify its calculation.

Amended spacing unit

99 The obligation to pay a compensatory royalty continues despite any change in the size of the First Nation spacing unit or the off-reserve spacing unit in which the triggering well is located if the two units remain adjoined.

End of compensatory royalty

100 (1) The obligation to pay a compensatory royalty ends if the holder

Notice to holder

(2) After determining whether a circumstance referred to in subsection 96(1) has been established, the Minister must send the holder a notice informing them of his or her determination and, if the obligation ends, the day on which it ends.

Final day of obligation

(3) The obligation to pay a compensatory royalty ends

Notice to council

(4) If the obligation to pay a compensatory royalty ends, the Minister must send the council a notice indicating that it has ended and the reasons why it has ended.

Transitional provision

101 Subject to subsection 97(6), sections 93 to 100 and 111 apply to any subsurface contract that was granted under the Indian Act or the Act.

Offset Wells
Failure to produce

102 (1) If an offset well fails to produce any oil or gas for three consecutive months after the offset period has ended, the holder must pay a compensatory royalty in respect of the triggering well whose production was to be offset.

Beginning of royalty obligation

(2) The obligation to pay the compensatory royalty begins on the first day of the month following the three-month period.

Notice to council

(3) The Minister must send the council a notice indicating that the holder has become obliged to pay a compensatory royalty.

Service Wells
Application for approval

103 (1) A well must not be used as a service well without the prior approval of the Minister.

Content of application

(2) The application for approval must be in the prescribed form and be accompanied by a copy of the provincial authority's approval of the service well. It must include the following information:

Approval

(3) The Minister must approve the proposed uses of the service well if

Notice to Minister

(4) The holder must send the Minister notice of any changes in the provincial authority's approval referred to in subsection (2).

Exception

104 Section 103 does not apply to a service well that is part of a project that has been approved by the provincial authority or a bitumen recovery project that has been approved by the Minister.

Transitional provision

105 Section 103 does not apply to a disposal rights agreement that was entered before these Regulations came into force.

Pooling, Production Allocation and Unit Agreements
Pooling

106 (1) If a well is completed in a First Nation spacing unit that is subject to more than one subsurface contract or in a spacing unit in which the First Nation's interests or rights are less than 100%, the Minister must determine the percentage of production from the well to be allocated to each contract in the spacing unit or to the First Nation's interests or rights, based on the area of the lands subject to each contract.

Notice to holder and council

(2) The Minister must give each holder and the council notice of the percentage of the production that is allocated to each contract in First Nation lands.

Multiple spacing unit production

107 (1) If a well is producing from more than one spacing unit and the lands from which it is producing are not entirely First Nation lands or are not subject to a single contract, the Minister must determine the percentage of production from the well to be allocated to the First Nation's interests or rights or to each contract, as the case may be, based on the criteria used by the provincial authority in making such allocations.

Notice to holder and council

(2) The Minister must send each holder and the council a notice indicating the percentage of the production that is allocated to the First Nation's interests or rights or to each contract, as the case may be.

Unit agreement

108 (1) The Minister may, with the prior approval of the council, enter into a unit agreement.

Allocation of production

(2) The calculation of royalties payable under a contract that is subject to a unit agreement must be based on the production allocated to each tract as specified in the agreement.

Surrender, Default and Cancellation
Surrender of subsurface rights

109 (1) The holder of a subsurface contract may surrender their rights in the contract by sending the Minister a notice of surrender in the prescribed form.

Partial surrender of subsurface rights

(2) In a partial surrender of subsurface rights,

Notice to council — subsurface contract

(3) When a subsurface contract is surrendered, the Minister must send a copy of the notice of surrender to the council and, in the case of a partial surrender, a copy of the amended contract.

Surrender of surface rights

110 (1) The holder of a surface contract may surrender their rights in the contract, in whole or in part, by applying in the prescribed form for the Minister's approval.

Notice to council — surface contract

(2) The Minister must send the council a copy of the application.

Approval

(3) The Minister must approve the surrender if

Adjusted rent

(4) If the surrender of rights in a surface contract is partial, the rent for subsequent years is reduced in proportion to the reduction of the lands. However, the rent must be no less than the rent payable for 1.6 hectares.

Notice to council

(5) When the surrender of a surface contract is approved, the Minister must send the council a notice of surrender.

Non-compliance notice

111 (1) If a holder fails to comply with their contract, the Act or these Regulations, the Minister may send them a notice that identifies the non-compliance and warns that the contract will be cancelled if the holder is in default.

Response to notice

(2) Within 30 days after the day on which the notice is received, the holder must remedy the non-compliance identified in the notice or, if the non-compliance does not relate to money owed under the Act, submit a plan to the Minister that shows how and when it will be remedied and why the proposed deadline is justified in the circumstances. Subsequently, the holder must remedy the non-compliance in accordance with the plan.

Deficient plan

(3) If the plan does not meet the requirements of subsection (2), the Minister must send the holder a notice to that effect that identifies its deficiencies.

Amended plan

(4) A holder that receives a notice sent under subsection (3) must

Default

(5) A holder that receives a notice sent under subsection (1) is in default if they do not comply with the requirements of subsection (2) or, if applicable, subsection (4).

Cancellation for default

(6) The Minister must cancel the contract of a holder that is in default.

Non-payment of compensatory royalty

(7) If a contract is to be cancelled for non-payment of a compensatory royalty, the Minister must cancel the rights conferred by the contract down to the base of the offset zone in the spacing unit to which the offset notice applies, except for any rights in a spacing unit referred to in any of paragraphs 63(1)(a) to (e).

Cancellation notice

(8) When a contract is cancelled, the Minister must send the holder a notice indicating that their contract is cancelled, the reason for the cancellation and its effective date.

Notice to council

(9) The Minister must send the council a copy of every notice sent under this section.

Continuing liability

112 When a contract ends, any liabilities for outstanding amounts that are owed under the contract, any liabilities for damages resulting from operations carried out under the contract and any obligations respecting abandonment, remediation or reclamation survive the end of the contract.

Administrative Monetary Penalties
Designated provisions

113 The provisions set out in Schedule 6 are designated as provisions whose contravention is a violation that may be proceeded with under sections 21 to 28 of the Act.

Transitional Provisions
Executive Director

114 The powers, duties and functions of the Executive Director under the Indian Oil and Gas Regulations, 1995 are to be exercised or performed by the Minister and any reference to the Executive Director in a contract granted under those Regulations is deemed to be a reference to the Minister.

Permits

115 Sections 15, 16 and 18 to 21 of the Indian Oil and Gas Regulations, 1995 continue to apply to permits granted under those Regulations.

Repeal

116 The Indian Oil and Gas Regulations, 1995 footnote 1 are repealed.

Coming into Force

S.C. 2009, c. 7

117 These Regulations come into force on the day on which section 1 of An Act to amend the Indian Oil and Gas Act comes into force, but if they are registered after that day, they come into force on the day on which they are registered.

SCHEDULE 1

(Subsections 2(5) and 25(1), paragraphs 29(2)(e) and 41(1)(a), subsection 44(3) and paragraphs 75(1)(d) and 110(3)(c))

Fees
Item

Column 1

Service

Column 2

Fee ($)

1 Subsurface contract application 250
2 Surface lease application 50
3 Right-of-way application 50
4 Exploration licence application 25
5 Assignment approval application 50
6 Partial surrender approval application 25
7 Record search 25

SCHEDULE 2

(Subsections 48(1) and (2))

Initial Term of Permits
Definitions

1 The following definitions apply in this schedule.

Area 1 refers to the lands in Area 1 in Schedule 2 to the Petroleum and Natural Gas Drilling Licence Regulation, B.C. Reg 10/82. (zone 1)

Area 2 refers to the lands in Area 2 in Schedule 2 to the Petroleum and Natural Gas Drilling Licence Regulation, B.C. Reg 10/82. (zone 2)

Area 3 refers to the lands in Area 3 in Schedule 2 to the Petroleum and Natural Gas Drilling Licence Regulation, B.C. Reg. 10/82. (zone 3)

Foothills Region refers to the lands in the Foothills Region referred to in Schedule 1 to the Petroleum and Natural Gas Tenure Regulation, Alta. Reg. 263/1997. (région des contreforts)

Northern Region refers to the lands in the Northern Region referred to in Schedule 1 to the Petroleum and Natural Gas Tenure Regulation, Alta. Reg. 263/1997. (région du Nord)

Plains Region refers to the lands in the Plains Region referred to in Schedule 1 to the Petroleum and Natural Gas Tenure Regulation, Alta. Reg. 263/1997. (région des plaines)

township means a township laid out in accordance with sections 55 to 61 of The Land Surveys Regulations, RSS c. L-4.1. (canton) (canton)

Table
Item

Column 1

Province

Column 2

Region

Column 3

Initial Term (Years)

1 Novia Scotia The entire province 3
2 New Brunswick The entire province 3
3 Manitoba The entire province 3
4 British Columbia Area 1 3
5   Area 2 4
6   Area 3 5
7 Saskatchewan Lands located south of Township 55 2
8   Lands located north of Township 54 but south of Township 66 3
9   Lands located north of Township 65 4
10 Alberta Plains Region 2
11   Northern Region 4
12   Foothills Region 5

SCHEDULE 3

(Subsections 1(1) and 52(3))

Zones — Intermediate Term
Definitions

1 The following definitions apply in this schedule.

ILND means the internal limit of a zone, whether upper or lower, that is not defined. (LIND)

KB means kelly bushing, that is, the point on the rotary drilling table from which downhole well log depths are measured. (FE)

NDE means not deep enough and, in relation to a reference well, means that the well was not drilled to a depth that was sufficient to penetrate the upper or lower limit of a particular zone. (FI)

NP means not present and in relation to a zone means that the zone is not present at the location where the reference well was drilled. (NP)

TVD means true vertical depth. (PVR)

Zones

2 (1) For each reserve specified in this schedule, the zones that may be selected are the zones set out in column 1 of the table that correspond to the well log data set out in column 2 that match the well log data for the well that was drilled or re-entered by the holder.

Multiple reference wells

(2) If there is more than one set of well log data in column 2, the set derived from the reference well that is nearest the earning well must be used to determine the zones.

Minister's determination

3 If a well is drilled into a zone that is not identified in a table to this schedule, the Minister must determine the upper and lower limits of the deepest zone penetrated by the well, based on a review of the log data that relate to other wells in the vicinity and on any log data that are available and relate to lands in the vicinity.

Alexander 134
Item

Column 1

Zone

Column 2

Well Log Data

00/11-11-56-27W4
Electric Log (ftKB)
02/6-15-56-27W4
Induction Log (mKB)
00/8-1-56-27W4
Density Log (mKB)
1 Edmonton, Belly River and Lea Park   surface to 615.0  
2 Waipiabi and Second White Specks   615.0 to 939.0  
3 Viking 3090 to 3250 939.0 to 989.0 934.5 to 979.5
4 Joli Fou 3250 to 3293 989.0 to 997.0 979.5 to 992.0
5 Mannville, including Upper Mannville, Glauconite, Ostracod, Basal Quartz “A” and Lower Basal Quartz 3293 to 4112 997.0 to NDE 992.0 to 1218.0
6 Wabamun 4112 to NDE NDE 1218.0 to 1384.5
7 Calmar NDE NDE 1384.5 to 1393.5
8 Nisku NDE NDE 1393.5 to NDE
9 Ireton NDE NDE NDE
10 Cooking Lake NDE NDE NDE
Alexander 134A
Item

Column 1

Zone

Column 2

Well Log Data

00/13-22-61-17W5
Neutron-Density Log (mKB )
00/3-32-63-22W5
Neutron-Density Log (mKB)
1 Edmonton, Belly River and Lea Park surface to 1147.7  
2 Wapiabi, Cardium and Second White Specks 1147.7 to 1663.7  
3 Viking and Joli Fou 1663.7 to 1688.3  
4 Mannville 1688.3 to 1948.1  
5 Fernie and Nordegg 1948.1 to 2024.3  
6 Montney 2024.3 to 2048.3  
7 Belloy 2048.3 to 2064.5  
8 Shunda 2064.5 to 2124.4  
9 Pekisko 2124.4 to 2170.0  
10 Banff and Exshaw 2170.0 to NDE 2472.0 to 2668.0
11 Wabamun   2668.0 to 2893.0
12 Graminia and Blueridge   2893.0 to 2946.0
13 Nisku   2946.0 to 3100.0
14 Ireton   3100.0 to 3273.0
15 Duvernay   3273.0 to 3334.8
16 Cooking Lake and Beaverhill Lake   3334.8 to 3385.0
17 Swan Hills   3385.0 to 3422.0
18 Watt Mountain   3422.0 to NDE
Alexis 133
Item

Column 1

Zone

Column 2

Well Log Data

00/10-23-55-4W5
Acoustilog
(mKB)
1 Edmonton, Belly River and Lea Park surface to 760.0
2 Wapiabi and Second White Specks 760.0 to 1125.0
3 Viking and Joli Fou 1125.0 to 1170.0
4 Mannville 1170.0 to 1328.5
5 Banff and Exshaw 1328.5 to 1480.5
6 Wabamun 1480.5 to 1661.0
7 Winterburn 1661.0 to 1707.5
8 Ireton 1707.5 to NDE
Alexis Whitecourt 232
Item

Column 1

Zone

Column 2

Well Log Data

00/2-31-60-12W5
Acoustilog
(mKB )
1 Edmonton, Belly River and Lea Park surface to 936.5
2 Wapiabi and Second White Specks 936.5 to 1381.3
3 Viking and Joli Fou 1381.3 to 1415.0
4 Mannville 1415.0 to 1655.0
5 Nordegg 1655.0 to 1691.0
6 Shunda and Pekisko 1691.0 to 1737.0
7 Banff and Exshaw 1737.0 to 1920.5
8 Wabamun 1920.5 to 2137.0
9 Winterburn 2137.0 to 2234.0
10 Ireton and Duvernay 2234.0 to 2575.5
11 Swan Hills 2575.5 to 2711.0
12 Watt Mountain 2711.0 to NDE
Amber River 211, Hay Lake 209 and Zama Lake 210
Item

Column 1

Zone

Column 2

Well Log Data

Amber river
00/11-20-114-6w6
Sonic Log (m)
Hay lake
00/4-1-112-5w6
Neutron Density Log (m)
Hay lake
00/6-28-112-5w6
Density Log (ft.)
Zama lake
00/2-12-112-8w6
Induction Log (m)
1 Wilrich Surface to 249.0 Surface to 242.0   Surface to 279.0
2 Bluesky et Gething 249.0 to 261.0 242.0 to 261.5   279.0 to 296.0
3 Banff 261.0 to 344.0 261.5 to 318.7   296.0 to 441.0
4 Wabamun 344.0 to 548.0 318.7 to FI LIND to 1712 441.0 to 633.0
5 Trout river, Kakisa, Redknife et Jean Marie 548.0 to 710.0   1712 to 2220 633.0 to 797.0
6 Fort simpson 710.0 to 1232.7   2220 to 3842 797.0 to 1305.5
7 Muskwa et Waterways 1232.7 to 1310.7   3842 to 4192 1305.5 to 1394.0
8 Slave point 1310.7 to 1387.0   4192 to 4396 1394.0 to 1478.0
9 Watt Mountain et Sulphur Point 1387.0 to 1422.0   4396 to 4525 1478.0 to 1524.0
10 Muskeg et Keg River 1422.0 to 1680.0   4525 to 5468 1524.0 to 1780.0
11 Chinchaga 1680.0 to FI   5468 to FI 1780.0 to FI
Beaver 152
Item

Column 1

Zone

Column 2

Well Log Data

00/4-6-82-3W6
Neutron-Density Log
(mKB)
1 Shaftesbury surface to 508.0
2 Paddy, Cadotte and Harmon 508.0 to 580.0
3 Notikewin and Falher 580.0 to 920.0
4 Bluesky and Gething 920.0 to 996.0
5 Fernie and Nordegg 996.0 to 1085.0
6 Montney 1085.0 to 1307.8
7 Belloy 1307.8 to 1358.0
8 Taylor Flat 1358.0 to 1395.0
9 Kiskatinaw 1395.0 to 1406.0
10 Golata 1406.0 to 1435.0
11 Debolt 1435.0 to NDE
Beaver Lake 131
Item

Column 1

Zone

Column 2

Well Log Data

00/7-3-66-13W4
Induction Log (mKB)
00/12-35-66-12W4
Induction Log (mKB)
00/6-20-66-13W4
Sonic Log (mKB)
1 Colorado shales surface to 294.5 surface to 308.0  
2 Viking and Joli Fou 294.5 to 335.0 308.0 to 348.3  
3 Mannville 335.0 to NDE 348.3 to 542.0 318.0 to 486.0
4 Grosmont NDE 542.0 to NDE 486.0 to 542.0
Big Island Cree Territory 124
Item

Column 1

Zone

Column 2

Well Log Data

31/7-26-62-25W3
Neutron-Density Log (mKB)
01/10-20-63-24W3
Neutron-Density Log (mKB)
1 Second White Specks   138.3 to 192.0
2 St. Walburg and Viking ILND to 286.0 192.0 to 272.4
3 Mannville 286.0 to NDE 272.4 to 502.0
4 Souris River   502.0 to NDE
Birdtail Creek 57
Item

Column 1

Zone

Column 2

Well Log Data

00/12-10-15-27W1
Neutron-Density Log (mKB)
00/3-21-15-27W1
Sonic Log (ftKB)
1 Second White Specks 244.0 to 369.0 800 to 1200
2 Swan River (Mannville) 369.0 to 408.5 1200 to 1340
3 Jurassic 408.5 to 479.0 1340 to 1554
4 Lodgepole 479.0 to 538.3 1554 to 1734
5 Bakken 538.3 to 540.3 1734 to 1742
6 Torquay 540.3 to 570.3 1742 to NDE
7 Birdbear 570.3 to NDE NDE
8 Duperow NDE NDE
Blood 148
Item

Column 1

Zone

Column 2

Well Log Data

00/6-35-5-25W4
Neutron Density Log (mKB)
00/12-28-7-23W4
Neutron Density Log (mKB)
00/6-24-8-23W4
Neutron Density Log (mKB)
1 Belly River and Pakowki surface to 1177.0 surface to 859.8 surface to 662.0
2 Milk River 1177.0 to 1278.3 859.8 to 975.3 662.0 to 783.0
3 Colorado Shale 1278.3 to 1629.0 975.3 to 1289.5 783.0 to 1086.5
4 Second White Specks and Barons 1629.0 to 1761.0 1289.5 to 1385.5 1086.5 to 1186.0
5 Bow Island 1761.0 to 1883.0 1385.5 to 1529.3 1186.0 to 1333.0
6 Mannville 1883.0 to 2090.0 1529.3 to 1727.5 1333.0 to NDE
7 Rierdon 2090.0 to 2187.5 1727.5 to 1807.8 NDE
8 Livingstonenote a 2187.5 to 2435.5 1807.8 to 1994.3 NDE
9 Banff and Exshawnote b 2435.5 to 2550.0 1994.3 to 2157.5 NDE
10 Big Valley and Stettler 2550.0 to 2720.5 2157.5 to 2309.0 NDE
11 Winterburn 2720.5 to NDE 2309.0 to NDE NDE
12 Woodbend NDE NDE NDE
Buck Lake 133C
Item

Column 1

Zone

Column 2

Well Log Data

00/6-20-45-5W5
Induction Log
(ftKB)
1 Belly River and Lea Park surface to 4650
2 Wapiabi 4650 to 5167
3 Cardium and Blackstone 5167 to 5590
4 Second White Specks 5590 to 6173
5 Viking and Joli Fou 6173 to 6316
6 Mannville 6316 to 6855
7 Nordegg 6855 to 6922
8 Pekisko 6922 to 6982
9 Banff 6982 to NDE
Carry The Kettle Nakoda First Nation 76-33
Item

Column 1

Zone

Column 2

Well Log Data

31/14-29-21-19W3
Induction Log (mKB)
1 Lea Park surface to 219.0
2 Milk River 219.0 to 397.6
3 Colorado 397.6 to NDE
Cold Lake 149, 149A, 149B
Item

Column 1

Zone

Column 2

Well Log Data

Cold Lake 149
00/2-13-61-3W4
Induction Log (mKB)
Cold Lake 149A & B
00/6-7-64-2W4
Induction Log (mKB)
1 Viking and Joli Fou 265.0 to 304.0  
2 Mannville 304.0 to 495.3 305.0 to NDE
3 Beaverhill Lake 495.3 to NDE NDE
Drift Pile River 150
Item

Column 1

Zone

Column 2

Well Log Data

00/10-6-74-12W5
Neutron-Density Log (mKB)
00/7-25-73-12W5
Density Log (mKB)
1 Second White Specks 219.5 to 310.0  
2 Shaftsbury 310.0 to 418.0 222.5 to 420.5
3 Peace River and Harmon 418.0 to 450.4 420.5 to 451.3
4 Spirit River 450.4 to 707.5 451.3 to 739.0
5 Bluesky and Gething 707.5 to 764.0 739.0 to 788.0
6 Shunda 764.0 to 830.0 788.0 to 799.0
7 Pekisko 830.0 to NDE 799.0 to 856.0
8 Banff NDE 856.0 to 1081.5
9 Wabamun NDE 1081.5 to 1350.0
10 Winterburn NDE 1350.0 to 1483.0
11 Ireton NDE 1483.0 to 1680.0
12 Leduc NDE 1680.0 to 1805.0
13 Beaverhill Lake NDE 1805.0 to 1926.5
14 Slave Point and FortVermillion NDE 1926.5 to 1960.5
15 Watt Mountain and Gilwood NDE 1960.5 to 1973.0
16 Muskeg NDE 1973.0 to NDE
Enoch Cree Nation 135
Item

Column 1

Zone

Column 2

Well Log Data

03/13-3-52-26W4
Induction Log (mKB)
1 Edmonton, Belly River and Lea Park surface to 691.0
2 Wapiabi and Second White Specks 691.0 to 1029.0
3 Viking and Joli Fou 1029.0 to 1076.0
4 Mannville 1076.0 to 1332.0
5 Wabamun 1332.0 to 1421.0
6 Graminia, Calmar and Nisku 1421.0 to 1502.0
7 Ireton, Leduc and Cooking Lake 1502.0 to NDE
Halfway River 168
Item

Column 1

Zone

Column 2

Well Log
Data
00/1-34-86-25W6
Sonic Log
(mKB TVD)
1 Wilrich surface to 710.0
2 Bluesky and Gething 710.0 to 840.5
3 Cadomin 840.5 to 889.0
4 Nikanassin 889.0 to 994.0
5 Fernie and Nordegg 994.0 to 1112.0
6 Pardonet and Baldonnel 1112.0 to 1150.0
7 Charlie Lake 1150.0 to 1466.5
8 Halfway 1466.5 to 1517.0
9 Doig 1517.0 to 1651.5
10 Montney 1651.5 to 1960.0
11 Belloy 1960.0 to NDE
Heart Lake 167
Item

Column 1

Zone

Column 2

Well Log Data

00/13-18-70-10W4
Induction Log (mKB)
1 Viking and Joli Fou 268.0 to 306.0
2 Mannville 306.0 to 502.0
3 Woodbend 502.0 to NDE
Horse Lakes 152B
Item

Column 1

Zone

Column 2

Well Log Data

00/8-27-73-12W6
Sonic Log
(mKB)
1 Puskwaskau, Badheart, Cardium and Kaskapau surface to 928.0
2 Doe Creek Member 928.0 to 976.0
3 Dunvegan 976.0 to 1140.0
4 Shaftsbury 1140.0 to 1468.0
5 Paddy 1468.0 to 1496.0
6 Cadotte and Harmon 1496.0 to 1553.0
7 Notikewin 1553.0 to 1625.0
8 Falher and Wilrich 1625.0 to 1879.0
9 Bluesky and Gething 1879.0 to 2021.5
10 Cadomin 2021.5 to 2050.5
11 Nikanassin 2050.5 to 2157.5
12 Fernie 2157.5 to 2248.0
13 Nordegg 2248.0 to 2275.0
14 Charlie Lake 2275.0 to 2477.5
15 Halfway 2477.5 to 2504.0
16 Doig 2504.0 to 2553.0
17 Montney 2553.0 to NDE
Kehewin 123
Item

Column 1

Zone

Column 2

Well Log Data

00/7-10-59-6W4
Induction Log (ftKB)
00/10-9-59-6W4note c
Induction Log (mKB)
1 Viking and Joli Fou 1053 to 1189  
2 Mannville 1189 to 1858 359.0 to NDE
3 Woodbend 1858 to NDE NDE
Little Pine 116 and Poundmaker 114
Item

Column 1

Zone

Column 2

Well Log Data

21/6-7-46-21W3
Induction Log
(mKB)
21/15-29-44-23W3note d
Neutron-Density Log (mKB)
11/2-33-44-24w3
Neutron-Density Log (mKB)
1 Second White Specks     458.3 to 543.0
2 Viking and Joli Fou     543.0 to 585.0
3 Mannville 437.5 to 601.0 532.0 to ILND 585.0 to 736.5
4 Duperow 601.0 to NDE   736.5 to NDE
Loon Lake 235 and Swampy Lake 236
Item

Column 1

Zone

Column 2

Well Log Data

00/1-20-86-9W5
Neutron-Density Log (mKB)
1 Clearwater 315.0 to 373.0
2 Banff 373.0 to 494.0
3 Wabamun 494.0 to 777.0
4 Winterburn 777.0 to 963.0
5 Ireton 963.0 to 1233.0
6 Beaverhill Lake 1233.0 to 1343.7
7 Slave Point and Fort Vermillion 1343.7 to 1377.5
8 Watt Mountain 1377.5 to 1382.7
9 Muskeg 1382.7 to 1452.0
10 Granite Wash 1452.0 to 1487.0
11 PreCambrian 1487.0 to NDE
Makaoo 120, Onion Lake 119-1, 119-2 and Seekaskootch 119
Item

Column 1

Zone

Column 2

Well Log Data

11/14-8-56-27W3
Neutron-Density Log (mKB )
00/11-23-54-1W4
Neutron-Density Log (mKB)
41/6-4-55-25W3
Neutron-Density Log (mKB)
1 Second White Specks   surface to 322.0 346.0 to 428.0
2 St. Walburg (La Biche (AB)) ILND to 433.5 322.0 to 365.0 428.0 to 478.8
3 Viking 433.5 to 474.4 365.0 to 402.0 478.8 to 515.4
4 Mannville 474.4 to 648.0 402.0 to 536.0 515.4 to ILND
5 Duperow 648.0 to NDE 536.0 to NDE  
Ministikwan 161 and Makwa 129
Item

Column 1

Zone

Column 2

Well Log Data

41/8-25-58-25W3
Neutron-Density Log (mKB)
31/8-34-58-25W3
Neutron-Density Log (mKB)
1 Second White Specks, St. Walburg and Viking 219.0 to 346.5 254.6 to 387.6
2 Mannville 346.5 to NDE 387.6 to 627.0
3 Duperow NDE 627.0 to NDE
Neekaneet Cree Nation 160A
Item

Column 1

Zone

Column 2

Well Log Data

21/8-32-7-28W3
Neutron-Density Log (mKB)
1 Belly River surface to 625.4
2 Lea Park and Ribstone Creek 625.4 to 807.0
3 Milk River 807.0 to 946.3
4 Medicine Hat 946.3 to 1107.0
5 Second White Specks 1107.0 to 1272.0
6 Viking and Joli Fou 1272.0 to 1390.3
7 Mannville 1390.3 to 1479.3
8 Vanguard 1479.3 to 1523.0
9 Shaunavan and Gravelbourg 1523.0 to 1574.5
10 Mission Canyon 1574.5 to NDE
Ocean Man 69 and Flying Dust First Nation 105
Item

Column 1

Zone

Column 2

Well Log Data

31/11-11-10-8W2
Neutron-Density Log (mKB)
01/9-30-10-7W2
Sonic Log (mKB)
1 Gravelbourg   ILND to 1102.0
2 Watrous   1102.0 to 1184.4
3 Alida and Tilston   1184.4 to NDE
4 Souris Valley ILND to 1433.5 NDE
5 Bakken 1433.5 to 1451.0 NDE
6 Torquay 1451.0 to NDE NDE
Pigeon Lake 138Anote e
Item

Column 1

Zone

Column 2

Well Log Data

00/12-36-46-28W4
Gamma
Ray-Neutron Log (ft.KB)
04/15-24-46-28W4
Neutron-Density Log (mKB)
00/9-18-46-27W4
Electric Log
(ft.KB)
00/12-20-47-27W4
Electric Log
(ft.KB)
1 Edmonton, Belly River and Lea Park   surface to 1036.0    
2 Wapiabi   1036.0 to 1197.0    
3 Cardium and Blackstone   1197.0 to 1281.3 3850 to 4020note f  
4 Second White Specks   1281.3 to 1423.7    
5 Viking and Joli Fou   1423.7 to 1472.0    
6 Upper Mannville   1472.0 to 1610.3    
7 Lower Mannville   1610.3 to NDE    
8 Wabamun 5591 to 6295      
9 Calmar and Nisku 6295 to 6492      
10 Ireton 6492 to 6670      
11 Leduc 6670 to NDE     6434 to 7210note g
Puskiakiwenin 122 and Unipouheos 121
Item

Column 1

Zone

Column 2

Well Log Data

00/11-21-56-3W4
Induction Log
(mKB)
00/6-16-57-3W4note h
Induction Log
(mKB)
00/13-26-57-4W4note i
Induction Log
(mKB )
00/8-16-58-3W4
Induction Log
(mKB)
1 Viking and Joli Fou 371.0 to 411.5      
2 Mannville 411.5 to 546.5 409.5 to NDE 416.5 to NDE 403.0 to 575.0
3 Woodbend 546.5 to NDE NDE NDE 575.0 to NDE
Red Pheasant 108
Item

Column 1

Zone

Column 2

Well Log Data

11/15-14-61-26W3
Neutron-Density Log (mKB)
11/11-5-60-23W3
Neutron-Density Log (mKB)
41/7-15-59-24W3
Neutron-Density Log (mKB)
1 Second White Specks   160.8 to 239.7 176.0 to 253.0
2 St.Walburg   239.7 to 279.0 253.0 to 300.0
3 Viking   279.0 to 324.0 300.0 to 339.5
4 Mannville 292.3 to ILND 324.0 to 586.0 339.5 to 576.0
5 Souris River   586.0 to NDE 576.0 to NDE
Saddle Lake 125
Item

Column 1

Zone

Column 2

Well Log Data

00/11-32-57-11W4
Induction Log (ft.KB)
02/6-29-57-13W4
Induction Log (mKB)
1 Second White Specks   393.0 to 491.0
2 Viking and Joli Fou 1412 to 1542 491.0 to 528.3
3 Mannville 1542 to 2132 528.3 to 710.7
4 Ireton 2132 to NDE 710.7 to 872.3
5 Cooking Lake NDE 872.3 to 934.0
6 Beaverhill Lake NDE 934.0 to NDE
Samson 137, 137A, Louis Bull 138B, Ermineskin 138 and Montana 139
Item

Column 1

Zone

Column 2

Well Log Data

00/6-17-46-24W4
Neutron-Density Log (mKB)
00/9-35-44-25W4
Neutron-Density Log ( mKB TVD)
00/14-32-44-25W4
Neutron-Density Log (mKB)
00/10-13-44-23W4
Neutron-Density Log (ft.KB)
1 Edmonton, Belly River and Lea Park surface to 831.0 surface to 944.0 surface to 925.0 surface to 2707
2 Wapiabi 831.0 to 1067.0 944.0 to 1183.3 925.0 to 1166.0 2707 to 3466
3 Second White Specks 1067.0 to 1199.0 1183.3 to 1311.0 1166.0 to 1295.3 3466 to 3866
4 Viking and Joli Fou 1199.0 to 1251.5 1311.0 to 1363.6 1295.3 to 1350.7 3866 to 4040
5 Mannville 1251.5 to 1439.3 1363.6 to 1558.2 1350.7 to 1530.0 4040 to 4815
6 Banff 1439.3 to 1451.0 NP 1530.0 to 1543.0 NP
7 Wabamun 1451.0 to 1613.7 1558.2 to 1772.6 1543.0 to 1763.0 4815 to NDE
8 Calmar and Nisku 1613.7 to 1665.5 1772.6 to NDE 1763.0 to 1818.3 NDE
9 Ireton 1665.5 to 1904.0 NDE 1818.3 to NDE NDE
10 Cooking Lake 1904.0 to NDE NDE NDE NDE
Sawridge 150G
Item

Column 1

Zone

Column 2

Well Log Data

00/2-6-73-5W5
Sonic Log (ft.KB)
00/4-19-71-4W5note j
Induction Log (ft.KB)
1 Colorado surface to 1248  
2 Viking 1248 to 1334  
3 Mannville 1334 to 2240  
4 Banff and Exshaw 2240 to 2440  
5 Wabamun 2440 to 3336  
6 Winterburn 3336 to 3647  
7 Ireton 3647 to 4888  
8 Waterways 4888 to 5450  
9 Slave Point 5450 to 5496  
10 Watt Mountain 5496 to 5578  
11 Gilwood 5578 to 5860 6112 to 6146note j
12 Muskeg 5860 to 5920  
13 Keg River 5920 to 6321  
14 Lower Elk Point 6321 to NDE  
Sharphead 141 (former reserve)
Item

Column 1

Zone

Column 2

Well Log Data

00/6-1-43-26W4
Induction Log (mKB)
00/14-2-43-26W4
Sonic Log (mKB)
1 Horseshoe Canyon   surface to 552.0
2 Belly River and Lea Park   552.0 to 1016.0
3 Wapiabi, Cardium and Blackstone   1016.0 to 1270.0
4 Second White Specks ILND to 1384.5 1270.0 to 1405.0
5 Viking and Joli Fou 1384.5 to 1436.0 1405.0 to NDE
6 Mannville 1436.0 to 1625.0 NDE
7 Banff and Exshaw 1625. 0 to1652.5 NDE
8 Wabamun 1652.5 to NDE NDE
Siksika 146
Item

Column 1

Zone

Column 2

Well Log Data

00/14-3-23-23W4
Sonic Log
(mKB)
00/5-19-22-23W4
Neutron-Density Log (mKB)
00/4-4-21-20W4
Neutron-Density Log (mKB)
00/2-29-20-20W4
Neutron-Density Log (mKB)
00/6-20-20-19W4
Sonic Log
(mKB)
1 Edmonton, Belly River and Pakowki surface to 854.5 surface to 810.0 surface to 593.0 surface to 630.0 surface to 656.0
2 Milk River 854.5 to 937.5 810.0 to 892.0 593.0 to 686.0 630.0 to 722.5 656.0 to 738.5
3 Upper Colorado and Medicine Hat 937.5 to 1242.0 892.0 to 1200.0 686.0 to 977.5 722.5 to 1018.6 738.5 to 1026.6
4 Second White Specks 1242.0 to 1370.7 1200.0 to 1330.0 977.5 to 1095.4 1018.6 to 1144.0 1026.6 to 1147.7
5 Viking 1370.7 to 1475.0 1330.0 to 1441.5 1095.4 to 1203.7 1144.0 to 1248.5 1147.7 to 1250.0
6 Mannville 1475.0 to 1647.0 1441.5 to 1595.5 1203.7 to 1350.0 1248.5 to 1431.3 1250.0 to 1413.7
7 Pekisko 1647.0 to 1752.0 1595.5 to NDE 1350.0 to NDE 1431.3 to 1477.3 1413.7 to 1476.3
8 Banff and Exshaw 1752.0 to 1896.0 NDE NDE 1477.3 to 1617.0 1476.3 to 1630.0
9 Wabamun 1896.0 to 2065.7 NDE NDE 1617.0 to 1753.0 1630.0 to 1755.0
10 Calmar and Nisku 2065.7 to 2096.0 NDE NDE 1753.0 to 1796.5 1755.0 to 1793.7
11 Ireton and Leduc 2096.0 to 2312.0 NDE NDE 1796.5 to NDE 1793.7 to NDE
12 Cooking Lake 2312.0 to 2365.0 NDE NDE NDE NDE
13 Beaverhill Lake 2365.0 to 2514.5 NDE NDE NDE NDE
14 Elk Point 2514.5 to NDE NDE NDE NDE NDE
Stoney 142, 143, 144 and Tsuut'ina Nation 145
Item

Column 1

Zone

Column 2

Well Log Data

00/8-13-27-3W5
Induction Log (mKB)
00/2-33-25-6W5note k
Neutron Log (ft.KB )
00/10-34-24-6W5(5-34)note l
Sonic Log (ft.KB )
00/5-24-27-6W5note m
Sonic Log (ft.KB )
1 Belly River surface to 1743.0      
2 Wapiabi 1743.0 to 2121.0      
3 Cardium and Blackstone 2121.0 to 2418.0      
4 Viking and Joli Fou 2418.0 to 2498.0      
5 Blairmorenote n 2498.0 to 2729.0      
6 Mount Head NP      
7 Turner Valley 2729.0 to 2775.0 11154 to 11485note k 11920 to 12280note l 9978 to 10198note m
8 Shunda 2775.0 to 2828.0      
9 Pekisko 2828.0 to 2929.0      
10 Banff and Exshaw 2929.0 to 3079.0      
11 Wabamun 3079.0 to 3318.0      
12 Winterburn 3318.0 to 3356.0      
13 Ireton 3356.0 to 3368.0      
14 Leduc 3368.0 to 3599.0      
15 Cooking Lake 3599.0 to NDE      
Sturgeon Lake 154
Item

Column 1

Zone

Column 2

Well Log Data

00/9-18-70-23W5
Sonic Log (ft.KB)
00/4-25-70-23W5
Sonic Log (ft.KB)
1 Wapiabi, Bad Heart and Kaskapau surface to 2721 surface to 2605
2 Dunvegan and Shaftesbury 2721 to 3467 2605 to 3327
3 Peace River and Harmon 3467 to 3623 3327 to 3482
4 Spirit River 3623 to 4573 3482 to 4440
5 Bluesky and Gething 4573 to 4805 4440 to 4586
6 Cadomin 4805 to 4890 4586 to 4658
7 Fernie and Nordegg 4890 to 5092 4658 to 4949
8 Montney 5092 to 5459 4949 to 5288
9 Belloy 5459 to 5590 5288 to 5373
10 Debolt 5590 to 6186 5373 to 5997
12 Shunda 6186 to 6473 5997 to 6290
13 Pekisko 6473 to 6674 6290 to 6486
14 Banff and Exshaw 6674 to 7397 6486 to 7228
15 Wabamun 7397 to 8184 7228 to 8021
16 Winterburn 8184 to 8496 8021 to 8422
17 Ireton and Leduc 8496 to NDE 8422 to 9316
18 Beaverhill Lake NDE 9316 to 9610
19 Slave Point NDE 9610 to 9660
20 Gilwood and Granite Wash NDE 9660 to 9730
21 PreCambrian NDE 9730 to NDE
Sucker Creek 150A
Item

Column 1

Zone

Column 2

Well Log Data

00/16-36-74-15W5
Sonic Log
(mKB)
1 Shaftesbury surface to 428
2 Paddy, Cadotte and Harmon 428 to 463
3 Spirit River 463 to 737
4 Bluesky and Gething 737 to 768
5 Debolt 768 to 863
6 Shunda 863 to 976
7 Pekisko 976 to 1031
8 Banff 1031 to 1265
9 Wabamun 1265 to 1535
10 Winterburn 1535 to 1657
11 Woodbend 1657 to 1956
12 Beaverhill Lake and Slave Point 1956 to 2084
13 Gilwood and Watt Mountain 2084 to 2113
14 Granite Wash 2113 to 2152
15 PreCambrian 2152 to NDE
Sunchild 202 and O'Chiese 203

Column

1 Item

Column 2

Zone

Column 3

Well Log Data

00/4-11-44-10W5
Neutron-Density Log (mKB)
00/10-15-43-10W5
Neutron-Density Log (mKB)
00/6-30-42-9W5
Neutron-Density Log (mKB)
1 Edmonton and Belly River surface to 1765.0 surface to 1742.0 surface to 1700.0
2 Upper Colorado 1765. 0 to 2120.0 1742.0 to 2126.0 1700.0 to 2062.0
3 Cardium 2120.0 to 2186.0 2126.0 to 2197.7 2062.0 to 2134.7
4 Lower Colorado 2186.0 to 2522.5 2197.7 to 2499.0 2134.7 to 2451.9
5 Viking 2522.5 to 2550.0 2499.0 to 2526.0 2451.9 to 2478.6
6 Upper Mannville 2550.0 to 2720.0 2526.0 to 2678.0 2478.6 to 2627.0
7 Lower Mannville 2720.0 to 2791.4 2678.0 to 2757.0 2627.0 to 2702.5
8 Fernie, Rock Creek and Poker Chip 2791.4 to 2833.0 2757.0 to 2794.8 2702.5 to 2741.8
9 Nordegg 2833.0 to 2861.0 2794.8 to 2824.0 2741.8 to 2771.0
10 Shunda 2861.0 to 2892.2 2824.0 to 2854.8 2771.0 to 2804.2
11 Pekisko 2892.2 to 2926.0 2854.8 to 2905.0 2804.2 to 2839.0
12 Banff and Exshaw 2926.0 to NDE 2905.0 to NDE 2839.0 to 3021.3
13 Wabamun NDE NDE 3021.3 to NDE
Thunderchild 115K and Thunderchild First Nation 115B, 115C, 115D, 115E, 115F, 115G, 115H, 115I, 115J, 115L, 115M, 115N, 115Q, 115R, 115S, 115T, 115U, 115V, 115W, 115X, 115Z
Item

Column 1

Zone

Column 2

Well Log Data

91/5-25-59-23W3
Neutron-Density Log (mKB )
21/16-3-52-20W3
Neutron-Density Log (mKB)
1 St. Walburg and Viking 231.6 to 320.8  
2 Mannville 320.8 to NDE 454.0 to 672.0
3 Devonian NDE 672.0 to NDE
Utikoomak Lake 155
Item

Column 1

Zone

Column 2

Well Log Data

00/6-30-80-9W5
Sonic Log (mKB)
12-28-80-9W5
Electric Log (ft.KB)
2-21-79-8W5
Electric Log (ft.KB)
1 Peace River and Spirit River 315.5 to 558.7    
2 Shunda and Pekisko 558.7 to 607.0    
3 Banff and Exshaw 607.0 to 884.0    
4 Wabamun 884.0 to 1125.0    
5 Winterburn 1125.0 to1267.0    
6 Ireton 1267.0 to 1568.0    
7 Beaverhill Lake 1568.0 to 1686.0    
8 Slave Point and Ft. Vermillion 1686.0 to 1718.0    
9 Watt Montain and Gilwood 1718.0 to 1724.0 5552 to 5576note o 5689 to 5771note p
10 Muskeg, Keg River and Granite Wash 1724.0 to 1755.0    
11 PreCambrian 1755.0 to NDE    
Wabamun 133A
Item

Column 1

Zone

Column 2

Well Log Data

00/15-23-52-4W5
Sonic Log
(mKB)
1 Belly River surface to 710.0
2 Lea Park 710.0 to 865.0
3 Wapiabi 865.0 to 1016.0
4 Cardium and Lower Colorado 1016.0 to 1245.0
5 Viking and Joli Fou 1245.0 to 1295.5
6 Mannville 1295.5 to 1474.0
7 Banff and Exshaw 1474.0 to 1631.0
8 Wabamun 1631.0 to 1790.0
9 Graminia, Blueridge, Calmar and Nisku 1790.0 to 1877.0
10 Ireton 1877.0 to NDE
Wabasca 166, 166A, 166B, 166C, 166D
Item

Column 1

Zone

Column 2
00/11-10-81-25W4
Induction Log
(ft.KB)
1 Pelican and Joli Fou 720 to 824
2 Mannville 824 to 1608
3 Wabamun 1608 to 1677
4 Winterburn 1677 to NDE
White Bear 70
Item

Column 1

Zone

Column 2

Well Log Data

01/5-15-10-2W2
Neutron Log
(ft.KB)
1 Viking 2670 to 2843
2 Mannville 2843 to 3200
3 Gravelbourg and Watrous 3200 to 3902
4 Tilston and Souris Valley 3902 to 4380
5 Bakken 4380 to 4420
6 Torquay 4420 to 4590
7 Birdbear 4590 to 4690
8 Duperow 4690 to 5214
9 Souris River 5214 to 5593
10 Dawson Bay 5593 to 5780
11 Prairie Evaporite 5780 to NDE
White Fish Lake 128
Item

Column 1

Zone

Column 2

Well Log Data

00/14-11-62-13W4note q
Induction Log (mKB)
00/10-16-62-12W4note r
Induction Log (mKB)
1 Viking and Joli Fou 347.6 to 386.0 347.0 to 383.5
2 Mannville 386.0 to NDE 383.5 to 539.5
3 Woodbend   539.5 to NDE
Woodland Cree 226, 227, 228
Item

Column 1

Zone

Column 2

Well Log Data

00/6-18-87-18W5
Sonic Log
(mKB)
00/7-24-86-14W5
Sonic Log
(mKB)
00/9-34-86-17W5
Neutron-Density Log
(mKB)
1 Bullhead surface to 494.0 surface to 475.0 surface to 498.0
2 Debolt, Shunda and Pekisko 494.0 to 753.0 475.0 to 518.5 498.0 to 504.0note s
3 Banff and Exshaw 753.0 to 1051.0 518.5 to 823.0  
4 Wabamun 1051.0 to 1312.0 823.0 to 1078.0  
5 Winterburn 1312.0 to 1397.0 1078.0 to 1205.5  
6 Ireton 1397.0 to 1662.0 1205.5 to 1509.0  
7 Beaverhill Lake 1662.0 to 1700.0 1509.0 to 1566.0  
8 Slave Point 1700.0 to NDE 1566.0 to 1613.5  
9 Granite Wash   1613.5 to 1614.0  
10 PreCambrian   1614.0 to NDE  

SCHEDULE 4

(Subsections 1(1) and 63(1))

Zones — Continuation

Definitions

1 The following definitions apply in this Schedule.

ILND means the internal limit of a zone, whether upper or lower, that is not defined. (LIND)

KB means kelly bushing, that is, the point on the rotary drilling table from which downhole well log depths are measured. (FE)

NDE means not deep enough and in relation to a reference well means that the well was not drilled to a depth that was sufficient to penetrate the upper or lower limit of a particular zone. (FI)

NP means not present and in relation to a zone means that the zone is not present at the location where the reference well was drilled. (NP)

TVD means true vertical depth. (PVR)

Zones

2 (1) In the case of a contract that is continued on the basis of any of the paragraphs of subsection 63(1) or under section 66 of these Regulations, for each reserve specified in this schedule the zones with respect to which continuation may be sought are the zones set out in column 1 of the table that correspond to the well log data set out in column 2.

Multiple reference wells

(2) If there is more than one set of well log data in column 2, the set derived from the reference well that is nearest the relevant spacing unit must be used to determine the zones that may be continued.

Unidentified zone

3 If the zone with respect to which the contract may be continued is not identified in a table to this Schedule, the Minister must determine the upper and lower limits of the relevant zone, based on a review of well log data that relate to wells in the vicinity of the relevant spacing unit and on any other well log data that are available and relate to lands in the vicinity.

Alexander 134
Item

Column 1

Zone

Column 2

Well Log Data

00/11-11-56-27W4note t
Electric Log (ft.KB)
02/6-15-56-27W4
Induction Log (m KB)
00/8-1-56-27W4
Density Log (mKB)
1 Edmonton and Belly River   surface to 485.0  
2 Lea Park   485.0 to 615.0  
3 Waipiabi   615.0 to 805.5  
4 Second White Specks   805.5 to 939.0  
5 Viking 3090 to 3250 939.0 to 989.0 934.5 to 979.5
6 Joli Fou 3250 to 3293 989.0 to 997.0 979.5 to 992.0
7 Mannville, including Upper Mannville and Glauconite 3293 to 3790 997.0 to 1150.5 992.0 to 1141.5
8 Ostracod 3790 to 3836 1150.5 to 1163.5 1141.5 to 1155.0
9 Basal Quartz "A" 3836 to 3852 1163.5 to 1172.0 1155.0 to 1161.0
10 Lower Basal Quartz 3852 to 4112 1172.0 to NDE 1161.0 to 1218.0
11 Wabamun 4112 to NDE NDE 1218.0 to 1384.5
12 Calmar and Nisku NDE NDE 1384.5 to 1393.5
13 Ireton NDE NDE NDE
14 Cooking Lake NDE NDE NDE
Alexander 134A
Item

Column 1

Zone

Column 2

Well Log Data

00/13-22-61-17W5
Neutron-Density Log
(mKB TVD)
00/3-32-63-22W5
Neutron Density Log
(mKB)
1 Edmonton and Belly River surface to 1055.6  
2 Lea Park 1055.6 to 1147.7  
3 Wapiabi and Cardium 1147.7 to 1406.5  
4 Second White Specks 1406.5 to 1663.7  
5 Viking 1663.7 to 1682.0  
6 Joli Fou 1682.0 to 1688.3  
7 Upper Mannville 1688.3 to 1904.2  
8 Bluesky 1904.2 to 1921.9  
9 Gething 1921.9 to 1948.1  
10 Fernie and Nordegg 1948.1 to 2024.3  
12 Montney 2024.3 to 2048.3  
13 Belloy 2048.3 to 2064.5  
14 Shunda 2064.5 to 2124.4  
15 Pekisko 2124.4 to 2170.0  
16 Banff and Exshaw 2170.0 to NDE 2472.0 to 2668.0
17 Wabamun   2668.0 to 2893.0
18 Graminia and Blueridge   2893.0 to 2946.0
19 Nisku   2946.0 to 3100.0
20 Ireton   3100.0 to 3273.0
21 Duvernay   3273.0 to 3334.8
22 Cooking Lake and Beaverhill Lake   3334.8 to 3385.0
23 Swan Hills   3385.0 to 3422.0
24 Watt Mountain   3422.0 to NDE
Alexis 133
Item

Column 1

Zone

Column 2

Well Log
Data

00/10-23-55-4W5
Acoustilog
mKB
1 Edmonton and Belly River surface to 617.0
2 Lea Park 617.0 to 760.0
3 Wapiabi 760.0 to 960.5
4 Second White Specks 960.5 to 1125.0
5 Viking 1125.0 to 1158.5
6 Joli Fou 1158.5 to 1170.0
7 Upper Mannville 1170.0 to 1319.0
8 Lower Mannville 1319.0 to 1328.5
9 Banff 1328.5 to 1478.0
10 Exshaw 1478.0 to 1480.5
11 Wabamun 1480.5 to1661.0
12 Winterburn 1661.0 to 1707.5
13 Ireton 1707.5 to NDE
14 Cooking Lake  
Alexis Whitecourt 232
Item

Column 1

Zone

Column 2

Well Log
Data


00/2-31-60-12W5
Acoustilog
mKB
1 Edmonton and Belly River surface to 837.0
2 Lea Park 837.0 to 936.5
3 Wapiabi 936.5 to 1169.0
4 Second White Specks 1169.0 to 1381.3
5 Viking 1381.3 to 1409.0
6 Joli Fou 1409.0 to 1415.0
7 Upper Mannville 1415.0 to 1606.0
8 Lower Mannville 1606.0 to 1655.0
9 Nordegg 1655.0 to 1691.0
10 Shunda 1691.0 to 1704.0
11 Pekisko 1704.0 to 1737.0
12 Banff 1737.0 to 1917.9
13 Exshaw 1917.9 to 1920.5
14 Wabamun 1920.5 to 2137.0
15 Winterburn 2137.0 to 2234.0
16 Ireton 2234.0 to 2535.0
17 Duvernay 2535.0 to 2575.5
18 Swan Hills 2575.5 to 2711.0
19 Watt Mountain 2711.0 to NDE
Amber River 211, Hay Lake 209 and Zama Lake 210
Item

Column 1

Zone

Column 2

Well Log Data

Amber river
00/11-20-114-6W6
Sonic Log
(mKB)
Hay lake
00/4-1-112-5W6
Neutron-Density
Log (mKB)
Hay lake
00/6-28-112-5W6
Density Log
(ft.KB)
Zama lake
00/2-12-112-8W6
Induction Log
(mKB)
1 Wilrich surface to 249.0 surface to 242.0   surface to 279.0
2 Bluesky and Gething 249.0 to 261.0 242.0 to 261.5   279.0 to 296.0
3 Banff 261.0 to 344.0 261.5 to 318.7   296.0 to 441.0
4 Wabamun 344.0 to 548.0 318.7 to NDE ILND to 1712 441.0 to 633.0
5 Trout River, Kakisa and Redknife 548.0 to 697.0   1712 to 2177 633.0 to 785.5
6 Jean Marie 697.0 to 710.0   2177 to 2220 785.5 to 797.0
7 Fort Simpson 710.0 to 1232.7   2220 to 3842 797.0 to 1305.5
8 Muskwa and Waterways 1232.7 to 1310.7   3842 to 4192 1305.5 to 1394.0
9 Slave Point 1310.7 to 1387.0   4192 to 4396 1394.0 to 1478.0
10 Watt Mountain 1387.0 to 1389.0   4396 to 4422 1478.0 to 1481.0
11 Sulphur Point 1389.0 to 1422.0   4422 to 4525 1481.0 to 1524.0
12 Muskeg and Keg River 1422.0 to 1680.0   4525 to 5468 1524.0 to 1780.0
13 Chinchaga 1680.0 to NDE   5468 to NDE 1780.0 to NDE
Beaver 152
Item

Column 1

Zone

Column 2

Well Log
Data

00/4-6-82-3W6
Neutron-Density Log (mKB)
1 Shaftesbury surface to 508.0
2 Paddy, Cadotte and Harmon 508.0 to 580.0
3 Notikewin and Falher 580.0 to 920.0
4 Bluesky and Gething 920.0 to 996.0
5 Fernie and Nordegg 996.0 to 1085.0
6 Montney 1085.0 to 1307.8
7 Belloy 1307.8 to 1358.0
8 Taylor Flat 1358.0 to 1395.0
9 Kiskatinaw 1395.0 to 1406.0
10 Golata 1406.0 to 1435.0
11 Debolt 1435.0 to NDE
Beaver Lake 131
Item

Column 1

Zone

Column 2

Well Log Data

00/7-3-66-13W4
Induction Log (mKB)
00/12-35-66-12W4
Induction Log (mKB)
00/6-20-66-13W4
Sonic Log (mKB)
1 Colorado Shales surface to 294.5 surface to 308.0  
2 Viking and Joli Fou 294.5 to 335.0 308.0 to 348.3  
3 Colony 335.0 to 344.5 348.3 to 358.6 318.0 to 486.0
4 Upper Grand Rapids 2A 344.5 to 365.0 358.6 to 383.0
5 Upper Grand Rapids 2B 365.0 to 383.3 383.0 to 402.0
6 Lower Grand Rapids 1 383.3 to 398.0 402.0 to 418.0
7 Lower Grand Rapids 2 398.0 to 421.0 418.0 to 445.3
8 Upper Clearwater 421.0 to 449.5 445.3 to 470.6
9 Lower Clearwater 449.5 to 483.5 470.6 to 500.3
10 McMurray 483.5 to NDE 500.3 to 542.0
11 Grosmont NDE 542.0 to NDE 486.0 to 542.0
Big Island Cree Territory 124
Item

Column 1

Zone

Column 2

Well Log Data

31/7-26-62-25W3
Neutron-Density Log (mKB)
01/10-20-63-24W3
Neutron-Density Log (mKB)
1 Second White Specks   138.3 to 192.0
2 St. Walburg   192.0 to 221.0
3 Viking ILND to 286.0 221.0 to 272.4
4 Colony and McLarennote u 286.0 to 316.0 272.4 to 300.8
5 Waseca 316.0 to 333.0 300.8 to ILND
6 Lower Mannville 333.0 to ILND  
7 Souris River   502.0 to NDE
Birdtail Creek 57
Item

Column 1

Zone

Column 2

Well Log Data

00/12-10-15-27W1
Neutron-Density Log (mKB)
00/3-21-15-27W1
Sonic Log (ft.KB)
1 Second White Specks 244.0 to 369.0 800 to 1200
2 Swan River (Mannville) 369.0 to 408.5 1200 to 1340
3 Jurassic 408.5 to 479.0 1340 to 1554
4 Lodgepole 479.0 to 538.3 1554 to 1734
5 Bakken 538.3 to 540.3 1734 to 1742
6 Torquay 540.3 to 570.3 1742 to NDE
7 Birdbear 570.3 to NDE NDE
8 Duperow NDE NDE
Blood 148
Item

Column 1

Zone

Column 2

Well Log Data

00/6-35-5-25W4
Neutron-Density Log (mKB)
00/12-28-7-23W4
Neutron-Density Log (mKB)
00/6-24-8-23W4
Neutron-Density Log (mKB)
1 Belly River surface to 1129.5 surface to 798.5 surface to 619.5
2 Pakowki 1129.5 to 1177.0 798.5 to 859.8 619.5 to 662.0
3 Milk River 1177.0 to 1278.3 859.8 to 975.3 662.0 to 783.0
4 Colorado Shale 1278.3 to 1629.0 975.3 to 1289.5 783.0 to 1086.5
5 Second White Specks 1629.0 to 1761.0 1289.5 to 1385.5 1086.5 to 1165.5
6 Barons NP NP 1165.5 to 1186.0
7 Bow Island 1761.0 to 1883.0 1385.5 to 1529.3 1186.0 to 1333.0
8 Mannville 1883.0 to 2090.0 1529.3 to 1727.5 1333.0 to NDE
9 Rierdon 2090.0 to 2187.5 1727.5 to 1807.8 NDE
10 Livingstonenote v 2187.5 to 2435.5 1807.8 to 1994.3 NDE
11 Banff 2435.5 to 2546.0 1994.3 to 2153.3 NDE
12 Exshawnote w 2546.0 to 2550.0 2153.3 to 2157.5 NDE
13 Big Valley and Stettler 2550.0 to 2720.5 2157.5 to 2309.0 NDE
14 Winterburn 2720.5 to NDE 2309.0 to NDE NDE
15 Woodbend NDE NDE NDE
Buck Lake 133C
Item

Column 1

Zone

Column 2

Well Log Data

00/6-20-45-5W5
Induction Log
(ft.KB)
1 Belly River surface to 4193
2 Lea Park 4193 to 4650
3 Wapiabi 4650 to 5167
4 Cardium 5167 to 5302
5 Blackstone 5302 to 5590
6 Second White Specks 5590 to 6173
7 Viking 6173 to 6270
8 Joli Fou 6270 to 6316
9 Mannville 6316 to 6855
10 Nordegg 6855 to 6922
11 Pekisko 6922 to 6982
12 Banff 6982 to NDE
Carry The Kettle Nakoda First Nation 76-33
Item

Column 1

Zone

Column 2

Well Log Data

31/14-29-21-19W3
Induction Log (mKB)
1 Lea Park surface to 219.0
2 Milk River 219.0 to 397.6
3 Colorado 397.6 to NDE
Cold Lake 149, 149A, 149B
Item

Column 1

Zone

Column 2

Well Log Data

Cold Lake (149)
00/2-13-61-3W4
Induction log (mKB)
Cold Lake (149A&B)
00/6-7-64-2W4
Induction log (m. KB)
1 Viking and Joli Fou 265.0 to 304.0  
2 Colony 304.0 to 319.0 305.0 to 324.3
3 McLaren 319.0 to 329.5 324.3 to 334.0
4 Waseca 329.5 to 346.0 334.0 to 350.0
5 Sparky 346.0 to 363.0 350.0 to 366.5
6 General Petroleum 363.0 to 373.0 366.5 to 378.0
7 Rex 373.0 to 411.5 378.0 to 408.0
8 Lloydminster 411.5 to 453.0 408.0 to 452.0
9 Cummings 453.0 to 495.3 452.0 to NDE
10 Beaverhill Lake 495.3 to NDE NDE
Drift Pile River 150
Item

Column 1

Zone

Column 2

Well Log Data

00/10-6-74-12W5
Neutron-Density Log (m KB)
00/7-25-73-12W5
Density Log (mKB)
1 Second White Specks 219.5 to 310.0  
2 Shaftsbury 310.0 to 418.0 222.5 to 420.5
3 Peace River and Harmon 418.0 to 450.4 420.5 to 451.3
4 Spirit River 450.4 to 707.5 451.3 to 739.0
5 Bluesky 707.5 to 739.0 739.0 to 763.0
6 Gething 739.0 to 764.0 763.0 to 788.0
7 Shunda 764.0 to 830.0 788.0 to 799.0
8 Pekisko 830.0 to NDE 799.0 to 856.0
9 Banff NDE 856.0 to 1081.5
10 Wabamun NDE 1081.5 to 1350.0
11 Winterburn NDE 1350.0 to 1483.0
12 Ireton NDE 1483.0 to 1680.0
13 Leduc NDE 1680.0 to 1805.0
14 Beaverhill Lake NDE 1805.0 to 1926.5
15 Slave Point NDE 1926.5 to 1950.0
16 Fort Vermillion NDE 1950.0 to 1960.5
17 Watt Mountain and Gilwood NDE 1960.5 to 1973.0
18 Muskeg NDE 1973.0 to NDE
Enoch Cree Nation 135
Item

Column 1

Zone

Column 2

Well Log Data

03/13-3-52-26W4
Induction Log (mKB)
00/14-3-52-26W4
Electric Log (mKB)
1 Edmonton and Belly River surface to 529.0  
2 Lea Park 529.0 to 691.0  
3 Wapiabi 691.0 to 890.0  
4 Second White Specks 890.0 to 1029.0  
5 Viking and Joli Fou 1029.0 to 1076.0  
6 Mannville 1076.0 to 1332.0  
7 Wabamun 1332.0 to 1421.0  
8 Graminia, Calmar and Nisku 1421.0 to 1502.0  
9 Ireton, Leduc and Cooking Lake 1502.0 to NDE 1573.4 to NDEnote x
Halfway River 168
Item

Column 1

Zone

Column 2

Well Log Data

00/1-34-86-25W6
Sonic Log
( mKB TVD)
1 Wilrich surface to 710.0
2 Bluesky and Gething 710.0 to 840.5
3 Cadomin 840.5 to 889.0
4 Nikanassin 889.0 to 994.0
5 Fernie and Nordegg 994.0 to 1112.0
6 Pardonet and Baldonnel 1112.0 to 1150.0
7 Charlie Lake 1150.0 to 1466.5
8 Halfway 1466.5 to 1517.0
9 Doig 1517.0 to 1651.5
10 Montney 1651.5 to 1960.0
11 Belloy 1960.0 to NDE
Heart Lake 167
Item

Column 1

Zone

Column 2

Well Log Data

00/13-18-70-10W4
Induction Log (mKB)
1 Viking and Joli Fou 268.0 to 306.0
2 Colony 306.0 to 330.5
3 Upper Grand Rapids 330.5 to 363.0
4 Lower Grand Rapids 363.0 to 409.5
5 Clearwater 409.5 to 461.5
6 McMurray 461.5 to 502.0
7 Woodbend 502.0 to NDE
Horse Lakes 152B
Item

Column 1

Zone

Column 2

Well Log Data

00/8-27-73-12W6
Sonic Log
(mKB)
1 Puskwaskau surface to 402.5
2 Badheart 402.5 to 446.0
3 Cardium 446.0 to 483.0
4 Kaskapau 483.0 to 928.0
5 Doe Creek Member 928.0 to 976.0
6 Dunvegan 976.0 to 1140.0
7 Shaftsbury 1140.0 to 1468.0
8 Paddy 1468.0 to 1496.0
9 Cadotte 1496.0 to 1521.0
10 Harmon 1521.0 to 1553.0
11 Notikewin 1553.0 to 1625.0
12 Falher 1625.0 to 1812.5
13 Wilrich 1812.5 to 1879.0
14 Bluesky 1879.0 to 1921.5
15 Gething 1921.5 to 2021.5
16 Cadomin 2021.5 to 2050.5
17 Nikanassin 2050.5 to 2157.5
18 Fernie 2157.5 to 2248.0
19 Nordegg 2248.0 to 2275.0
20 Charlie Lake 2275.0 to 2477.5
21 Halfway 2477.5 to 2504.0
22 Doig 2504.0 to 2553.0
23 Montney 2553.0 to NDE
Kehewin 123
Item

Column 1

Zone

Column 2

Well Log Data

00/7-10-59-6W4
Induction Log (ft. KB)
00/10-9-59-6W4note y
Induction Log (mKB)
1 Viking and Joli Fou 1053 to 1189  
2 Colony 1189 to 1218 359.0 to 386.0
3 McLaren 1218 to 1261 NP
4 Waseca 1261 to 1315 386.0 to 401.0
5 Sparky 1315 to 1381 401.0 to 421.0
6 General Petroleum 1381 to 1490 421.0 to 457.0
7 Rex-Lloydminster 1490 to 1644 457.0 to 499.0
8 Cummings 1644 to 1858 499.0 to NDE
9 Woodbend 1858 to NDE NDE
Little Pine 116 and Poundmaker 114
Item

Column 1

Zone

Column 2

Well Log Data

21/6-7-46-21W3
Induction Log
(mKB)
21/15-29-44-23W3note z
Neutron-Density Log (mKB)
11/2-33-44-24w3
Neutron-Density Log (mKB)
1 Second White Specks     458.3 to 543.0
2 Viking and Joli Fou     543.0 to 585.0
3 Colony 437.5 to 459.0 532.0 to 554.0 585.0 to 600.8
4 McLaren 459.0 to 469.0 554.0 to 569.0 600.8 to 611.5
5 Waseca 469.0 to 485.5 569.0 to 588.0 611.5 to 634.7
6 Sparky 485.5 to 501.0 588.0 to 611.0 634.7 to 646.0
7 General Petroleum 501.0 to 518.3 611.0 to ILND 646.0 to 656.5
8 Rex 518.3 to 531.0   656.5 to 668.7
9 Lloydminster 531.0 to 543.3   668.7 to 683.4
10 Cummings 543.3 to 573.3   683.4 to 702.0
11 Dina 573.3 to 601.0   702.0 to 736.5
12 Duperow 601.0 to NDE   736.5 to NDE
Loon Lake 235 and Swampy Lake 236
Item

Column 1

Zone

Column 2

Well Log Data


00/1-20-86-9W5
Neutron-Density Log (mKB)
1 Clearwater 315.0 to 373.0
2 Banff 373.0 to 494.0
3 Wabamun 494.0 to 777.0
4 Winterburn 777.0 to 963.0
5 Ireton 963.0 to 1233.0
6 Beaverhill Lake 1233.0 to 1343.7
7 Slave Point 1343.7 to 1361.0
8 Fort Vermillion 1361.0 to 1377.5
9 Watt Mountain 1377.5 to 1382.7
10 Muskeg 1382.7 to 1452.0
11 Granite Wash 1452.0 to 1487.0
12 PreCambrian 1487.0 to NDE
Makaoo 120, Onion Lake 119-1, 119-2 and Seekaskootch 119
Item

Column 1

Zone

Column 2

Well Log Data

11/14-8-56-27W3
Neutron-Density Log (mKB TVD)
00/11-23-54-1W4
Neutron-Density Log (mKB)
41/6-4-55-25W3
Neutron-Density Log (mKB)
1 Second White Specks   surface to 322.0 346.0 to 428.0
2 St. Walburg (La Biche (AB)) ILND to 433.5 322.0 to 365.0 428.0 to 478.8
3 Viking 433.5 to 474.4 365.0 to 402.0 478.8 to 515.4
4 Colony 474.4 to 488.9 402.0 to 415.0 515.4 to ILND
5 McLaren 488.9 to 500.3 415.0 to 429.5  
6 Waseca 500.3 to 517.9 429.5 to 441.0  
7 Sparky 517.9 to 534.0 441.0 to 464.0  
8 General Petroleum 534.0 to 548.9 464.0 to 476.0  
9 Rex 548.9 to 582.0 476.0 to 499.0  
10 Lloydminster 582.0 to 602.6 499.0 to 515.0  
11 Cummings and Dina 602.6 to 648.0 515.0 to 536.0  
12 Duperow 648.0 to NDE 536.0 to NDE  
Ministikwan 161 and Makwa 129
Item

Column 1

Zone

Column 2

Well Log Data

41/8-25-58-25W3
Neutron-Density Log (mKB)
31/8-34-58-25W3
Neutron-Density Log (mKB)
1 Second White Specks, St. Walburg and Viking 219.0 to 346.5 254.6 to 387.6
2 Colony 346.5 to 371.0 387.6 to 408.0
3 McLaren 371. 0 to 383.0 408.0 to 421.0
4 Waseca 383.0 to 407.0 421.0 to 440.0
5 Sparky 407.0 to 422.3 440.0 to 460.0
6 General Petroleum 422.3 to 433.0 460.0 to 471.2
7 Rex, Lloydminster, Cummings and Dina 433.0 to NDE 471.2 to 627.0
8 Duperow NDE 627.0 to NDE
Neekaneet Cree Nation 160A
Item

Column 1

Zone

Column 2

Well Log Data

21/8-32-7-28W3
Neutron-Density Log (mKB)
1 Belly River surface to 625.4
2 Lea Park 625.4 to 658.4
3 Ribstone Creek 658.4 to 807.0
4 Milk River 807.0 to 946.3
5 Medicine Hat 946.3 to 1107.0
6 Second White Specks 1107.0 to 1272.0
7 Viking and Joli Fou 1272.0 to 1390.3
8 Mannville 1390.3 to 1479.3
9 Vanguard 1479.3 to 1523.0
10 Shaunavan 1523.0 to 1562.0
11 Gravelbourg 1562.0 to 1574.5
12 Mission Canyon 1574.5 to NDE
Ocean Man 69 and Flying Dust First Nation 105
Item

Column 1

Zone

Column 2

Well Log Data

31/11-11-10-8W2
Neutron-Density Log (mKB)
01/9-30-10-7W2
Sonic Log (mKB)
1 Gravelbourg   ILND to 1102.0
2 Watrous   1102.0 to 1184.4
3 Alida and Tilston   1184.4 to NDE
4 Souris Valley ILND to 1433.5 NDE
5 Bakken 1433.5 to 1451.0 NDE
6 Torquay 1451.0 to NDE NDE
Pigeon Lake 138Anote 1a
Item

Column 1

Zone

Column 2

Well Log Data

00/12-36-46-28W4
Gamma
Ray-Neutron Log (ft.KB)
04/15-24-46-28W4
Neutron-Density Log
(mKB)

00/9-18-46-27W4
Electric Log
(ft.KB)

00/12-20-47-27W4
Electric Log
(ft.KB)
1 Edmonton, Belly River and Lea Park   surface to 1036.0    
2 Wapiabi   1036.0 to 1197.0    
3 Cardium and Blackstone   1197.0 to 1281.3 3850 to 4020note 1b  
4 Second White Specks   1281.3 to 1423.7    
5 Viking and Joli Fou   1423.7 to 1472.0    
6 Upper Mannville   1472.0 to 1610.3    
7 Lower Mannville   1610.3 to NDE    
8 Wabamun 5591 to 6295      
9 Calmar and Nisku 6295 to 6492      
10 Ireton 6492 to 6670      
11 Leduc 6670 to NDE     6434 to 7210note 1c
Puskiakiwenin 122 and Unipouheos 121
Item

Column 1

Zone

Column 2

Well Log Data

00/11-21-56-3W4
Induction Log (mKB)
00/6-16-57-3W4note 1d
Induction Log (mKB)
00/13-26-57-4W4note 1d
Induction Log
(mKB TVD)
00/8-16-58-3W4
Induction Log (mKB)
1 Viking and Joli Fou 371.0 to 411.5      
2 Colony 411.5 to 427.5 409.5 to 420.0 416.5 to 427.5 403.0 to 420.0
3 McLaren 427.5 to 436.5 420.0 to 441.0 427.5 to 444.3 420.0 to 428.6
4 Waseca 436.5 to 449.5 441.0 to 456.0 444.3 to 462.7 428.6 to 447.0
5 Sparky 449.5 to 472.0 456.0 to 475.0 462.7 to 484.3 447.0 to 460.5
6 General Petroleum 472.0 to 485.0 475.0 to 488.5 484.3 to 498.0 460.5 to 475.6
7 Rex 485.0 to 491.0 488.5 to 498.5 498.0 to 509.2 475.6 to 487.5
8 Lloydminster 491.0 to 528.0 498.5 to 537.0 509.2 to NDE 487.5 to 533.0
9 Cummings 528.0 to 546.5 537.0 to NDE NDE 533.0 to 575.0
10 Woodbend 546.5 to NDE NDE NDE 575.0 to NDE
Red Pheasant 108
Item

Column 1

Zone

Column 2

Well Log Data

11/15-14-61-26W3
Neutron-Density Log (mKB)
11/11-5-60-23W3
Neutron-Density Log (mKB)
41/7-15-59-24W3
Neutron-Density Log (mKB)
1 Second White Specks   160.8 to 239.7 176.0 to 253.0
2 St. Walburg   239.7 to 279.0 253.0 to 300.0
3 Viking   279.0 to 324.0 300.0 to 339.5
4 Mannville 292.3 to ILND 324.0 to 586.0 339.5 to 576.0
5 Souris River   586.0 to NDE 576.0 to NDE
Saddle Lake 125
Item

Column 1

Zone

Column 2

Well Log Data

00/11-32-57-11W4
Induction Log (ft.KB)
02/6-29-57-13W4note 1e
Induction Log (mKB)
1 Second White Specks   393.0 to 491.0
2 Viking and Joli Fou 1412 to 1542 491.0 to 528.3
3 Colony 1542 to 1582 528.3 to ILND
4 Upper Grand Rapids 1582 to 1710  
5 Lower Grand Rapids 1710 to 1844  
6 Clearwater 1844 to 2025  
7 McMurray 2025 to 2132 ILND to 710.7
8 Ireton 2132 to NDE 710.7 to 872.3
9 Cooking Lake NDE 872.3 to 934.0
10 Beaverhill Lake NDE 934.0 to NDE
Samson 137, 137A, Louis Bull 138B, Ermineskin 138 and Montana 139
Item

Column 1

Zone

Column 2

Well Log Data

00/6-17-46-24W4
Neutron-Density Log (mKB)
00/9-35-44-25W4
Neutron-Density Log (mKB TVD)
00/14-32-44-25W4
Neutron-Density Log (mKB)
00/10-13-44-23W4
Neutron-Density Log (ft.KB)
1 Edmonton and Belly River surface to 702.0 surface to 817.5 surface to 793.0 surface to 2230
2 Lea Park 702.0 to 831.0 817.5 to 944.0 793.0 to 925.0 2230 to 2707
3 Wapiabi 831.0 to 1067.0 944.0 to 1183.3 925.0 to 1166.0 2707 to 3466
4 Second White Specks 1067.0 to 1199.0 1183.3 to 1311.0 1166.0 to 1295.3 3466 to 3866
5 Viking 1199.0 to 1229.7 1311.0 to 1342.0 1295.3 to 1330.0 3866 to 3970
6 Joli Fou 1229.7 to 1251.5 1342.0 to 1363.6 1330.0 to 1350.7 3970 to 4040
7 Mannville 1251.5 to 1439.3 1363.6 to 1558.2 1350.7 to 1530.0 4040 to 4815
8 Banff 1439.3 to 1451.0 NP 1530.0 to 1543.0 NP
9 Wabamun 1451.0 to 1613.7 1558.2 to 1772.6 1543.0 to 1763.0 4815 to NDE
10 Calmar and Nisku 1613.7 to 1665.5 1772.6 to NDE 1763.0 to 1818.3 NDE
11 Ireton 1665.5 to 1904.0 NDE 1818.3 to NDE NDE
12 Cooking Lake 1904.0 to NDE NDE NDE NDE
Sawridge 150G
Item

Column 1

Zone

Column 2

Well Log Data

00/2-6-73-5W5
Sonic Log (ft.KB)
00/4-19-71-4W5note 1f
Induction Log (ft.KB)
1 Colorado surface to 1248  
2 Viking 1248 to 1334  
3 Mannville 1334 to 2240  
4 Banff and Exshaw 2240 to 2440  
5 Wabamun 2440 to 3336  
6 Winterburn 3336 to 3647  
7 Ireton 3647 to 4888  
8 Waterways 4888 to 5450  
9 Slave Point 5450 to 5496  
10 Watt Mountain 5496 to 5578  
11 Gilwood 5578 to 5860 6112 to 6146 note 1f
12 Muskeg 5860 to 5920  
13 Keg River 5920 to 6321  
14 Lower Elk Point 6321 to NDE  
Sharphead 141 (former reserve)
Item

Column 1

Zone

Column 2

Well Log Data

00/6-1-43-26W4
Induction Log (mKB)
00/14-2-43-26W4
Sonic Log (mKB)
1 Horseshoe Canyon   surface to 552.0
2 Belly River and Lea Park   552.0 to 1016.0
3 Wapiabi, Cardium and Blackstone   1016.0 to 1270.0
4 Second White Specks ILND to 1384.5 1270.0 to 1405.0
5 Viking and Joli Fou 1384.5 to 1436.0 1405.0 to NDE
6 Mannville 1436.0 to 1625.0 NDE
7 Banff and Exshaw 1625.0 to 1652.5 NDE
8 Wabamun 1652.5 to NDE NDE
Siksika 146
Item

Column 1

Zone

Column 2

Well Log Data

00/14-3-23-23W4
Sonic Log
(mKB)
00/5-19-22-23W4
Neutron-Density Log (mKB)
00/4-4-21-20W4
Neutron-Density Log (mKB)
00/2-29-20-20W4
Neutron-Density Log (mKB)
00/6-20-20-19W4
Sonic Log
(mKB)
1 Edmonton and Belly River surface to 812.0 surface to 763.5 surface to 548.5 surface to 585.0 surface to 603.5
2 Pakowki 812.0 to 854.5 763.5 to 810.0 548.5 to 593.0 585.0 to 630.0 603.5 to 656.0
3 Milk River 854.5 to 937.5 810.0 to 892.0 593.0 to 686.0 630.0 to 722.5 656.0 to 738.5
4 Upper Colorado, including Medicine Hat 937.5 to 1242.0 892.0 to 1200.0 686.0 to 977.5 722.5 to 1018.6 738.5 to 1026.6
5 Second White Specks 1242.0 to 1370.7 1200.0 to 1330.0 977.5 to 1095.4 1018.6 to 1144.0 1026.6 to 1147.7
6 Viking Lag Sand NP 1330.0 to 1333.0 1095.4 to 1101.0 NP NP
7 Viking (Bow Island) 1370.7 to 1475.0 1333.0 to 1441.5 1101.0 to 1203.7 1144.0 to 1248.5 1147.7 to 1250.0
8 Mannville 1475.0 to 1647.0 1441.5 to 1595.5 1203.7 to 1350.0 1248.5 to 1431.3 1250.0 to 1413.7
9 Pekisko 1647.0 to 1752.0 1595.5 to NDE 1350.0 to NDE 1431.3 to 1477.3 1413.7 to 1476.3
10 Banff and Exshaw 1752.0 to 1896.0 NDE NDE 1477.3 to 1617.0 1476.3 to 1630.0
11 Wabamun 1896.0 to 2065.7 NDE NDE 1617.0 to 1753.0 1630.0 to 1755.0
12 Calmar and Nisku 2065.7 to 2096.0 NDE NDE 1753.0 to 1796.5 1755.0 to 1793.7
13 Ireton and Leduc 2096.0 to 2312.0 NDE NDE 1796.5 to NDE 1793.7 to NDE
14 Cooking Lake 2312.0 to 2365.0 NDE NDE NDE NDE
15 Beaverhill Lake 2365.0 to 2514.5 NDE NDE NDE NDE
16 Elk Point 2514.5 to NDE NDE NDE NDE NDE
Stoney 142,143,144 and Tsuut'ina Nation 145
Item

Column 1

Zone

Column 2

Well Log Data

00/8-13-27-3W5
Induction Log (mKB)
00/2-33-25-6W5note 1g
Neutron Log
(ft.KB )
00/10-34-24-6W5(5-34)note 1h
Sonic Log (ft.KB )
00/5-24-27-6W5note 1iSonic Log
(ft.KB )
1 Belly River surface to 1743.0      
2 Wapiabi 1743.0 to 2121.0      
3 Cardium and Blackstone 2121.0 to 2418.0      
4 Viking and Joli Fou 2418.0 to 2498.0      
5 Blairmorenote 1j 2498.0 to 2729.0      
6 Mount Head NP      
7 Turner Valley 2729.0 to 2775.0 11154 to 11485note 1g 11920 to 12280note 1h 9978 to 10198note 1i
8 Shunda 2775.0 to 2828.0      
9 Pekisko 2828.0 to 2929.0      
10 Banff and Exshaw 2929.0 to 3079.0      
11 Wabamun 3079.0 to 3318.0      
12 Winterburn 3318.0 to 3356.0      
13 Ireton 3356.0 to 3368.0      
14 Leduc 3368.0 to 3599.0      
15 Cooking Lake 3599.0 to NDE      
Sturgeon Lake 154
Item

Column 1

Zone

Column 2

Well Log Data

00/9-18-70-23W5
Sonic Log (ft.KB)
00/4-25-70-23W5
Sonic Log (ft.KB)
1 Wapiabi surface to 1844 surface to 1755
2 Bad Heart 1844 to 1897 1755 to 1795
3 Kaskapau 1897 to 2721 1795 to 2605
4 Dunvegan 2721 to 2960 2605 to 2835
5 Shaftesbury 2960 to 3467 2835 to 3327
6 Peace River 3467 to 3540 3327 to 3395
7 Harmon 3540 to 3623 3395 to 3482
8 Spirit River 3623 to 4573 3482 to 4440
9 Bluesky and Gething 4573 to 4805 4440 to 4586
10 Cadomin 4805 to 4890 4586 to 4658
11 Fernie and Nordegg 4890 to 5092 4658 to 4949
12 Montney 5092 to 5459 4949 to 5288
13 Belloy 5459 to 5590 5288 to 5373
14 Debolt 5590 to 6186 5373 to 5997
15 Shunda 6186 to 6473 5997 to 6290
16 Pekisko 6473 to 6674 6290 to 6486
17 Banff 6674 to 7378 6486 to 7208
18 Exshaw 7378 to 7397 7208 to 7228
19 Wabamun 7397 to 8184 7228 to 8021
20 Winterburn 8184 to 8496 8021 to 8422
21 Ireton 8496 to 8637 8422 to 9316
22 Leduc 8637 to NDE NP
23 Beaverhill Lake NDE 9316 to 9610
24 Slave Point NDE 9610 to 9660
25 Gilwood and Granite Wash NDE 9660 to 9730
26 PreCambrian NDE 9730 to NDE
Sucker Creek 150A
Item

Column 1

Zone

Column 2

Well Log Data

00/16-36-74-15W5
Sonic Log
(mKB)
1 Shaftesbury surface to 428
2 Paddy, Cadotte and Harmon 428 to 463
3 Spirit River 463 to 737
4 Bluesky and Gething 737 to 768
5 Debolt 768 to 863
6 Shunda 863 to 976
7 Pekisko 976 to 1031
8 Banff 1031 to 1265
9 Wabamun 1265 to 1535
10 Winterburn 1535 to 1657
11 Woodbend 1657 to 1956
12 Beaverhill Lake and Slave Point 1956 to 2084
13 Gilwood and Watt Mountain 2084 to 2113
14 Granite Wash 2113 to 2152
15 PreCambrian 2152 to NDE
Sunchild 202 and O'Chiese 203
Item

Column 1

Zone

Column 2

Well Log Data

00/4-11-44-10W5
Neutron-Density Log (mKB)
00/10-15-43-10W5
Neutron-Density Log (mKB)
00/6-30-42-9W5
Neutron-Density Log (mKB)
1 Edmonton and Belly River surface to 1765.0 surface to 1742.0 surface to 1700.0
2 Upper Colorado 1765.0 to 2120.0 1742.0 to 2126.0 1700.0 to 2062.0
3 Cardium 2120.0 to 2186.0 2126.0 to 2197.7 2062.0 to 2134.7
4 Lower Colorado 2186.0 to 2522.5 2197.7 to 2499.0 2134.7 to 2451.9
5 Viking 2522.5 to 2550.0 2499.0 to 2526.0 2451.9 to 2478.6
6 Upper Mannville 2550.0 to 2720.0 2526.0 to 2678.0 2478.6 to 2627.0
7 Lower Mannville 2720.0 to 2791.4 2678.0 to 2757.0 2627.0 to 2702.5
8 Fernie, Rock Creek and Poker Chip 2791.4 to 2833.0 2757.0 to 2794.8 2702.5 to 2741.8
9 Nordegg 2833.0 to 2861.0 2794.8 to 2824.0 2741.8 to 2771.0
10 Shunda 2861.0 to 2892.2 2824.0 to 2854.8 2771.0 to 2804.2
11 Pekisko 2892.2 to 2926.0 2854.8 to 2905.0 2804.2 to 2839.0
12 Banff and Exshaw 2926.0 to NDE 2905.0 to NDE 2839.0 to 3021.3
13 Wabamun NDE NDE 3021.3 to NDE
Thunderchild 115K and Thunderchild First Nation 115B, 115C, 115D, 115E, 115F, 115G, 115H, 115I, 115J, 115L, 115M, 115N, 115Q, 115R, 115S, 115T, 115U, 115V, 115W, 115X, 115Z
Item

Column 1

Zone

Column 2

Well Log Data

91/5-25-59-23W3
Neutron-Density Log (mKB )
21/16-3-52-20W3
Neutron-Density Log (mKB)
1 St. Walburg 231.6 to 274.4  
2 Viking 274.4 to 320.8  
3 Colony 320.8 to 340.0 454.0 to 478.0
4 McLaren 340.0 to 352.0 478.0 to 489.0
5 Waseca 352.0 to ILND 489.0 to 516.0
6 Sparky   516.0 to 546.0
7 General Petroleum   546.0 to 575.0
8 Rex   575.0 to 608.0
9 Lloydminster   608.0 to 646.0
10 Cummings   646.0 to 672.0
11 Devonian   672.0 to NDE
Utikoomak Lake 155
Item

Column 1

Zone

Column 2

Well Log Data

00/6-30-80-9W5
Sonic Log (mKB)
12-28-80-9W5
Electric Log (ft.KB)
2-21-79-8W5
Electric Log (ft.KB)
1 Peace River and Spirit River 315.5 to 558.7    
2 Shunda and Pekisko 558.7 to 607.0    
3 Banff and Exshaw 607.0 to 884.0    
4 Wabamun 884.0 to 1125.0    
5 Winterburn 1125.0 to1267.0    
6 Ireton 1267.0 to 1568.0    
7 Beaverhill Lake 1568.0 to 1686.0    
8 Slave Point and Fort Vermillion 1686.0 to 1718.0    
9 Watt Montain and Gilwood 1718.0 to 1724.0 5552 to 5576note 1k 5689 to 5771note 1l
10 Muskeg and Keg River 1724.0 to 1750.0    
11 Granite Wash 1750.0 to 1755.0    
12 PreCambrian 1755.0 to NDE    
Wabamun 133A
Item

Column 1

Zone

Column 2

Well Log Data

00/15-23-52-4W5
Sonic Log
(mKB)
1 Belly River surface to 710.0
2 Lea Park 710.0 to 865.0
3 Wapiabi 865.0 to 1016.0
4 Cardium and Lower Colorado 1016.0 to 1245.0
5 Viking 1245.0 to 1276.0
6 Joli Fou 1276.0 to 1295.5
7 Upper Mannville 1295.5 to 1424.0
8 Glauconite 1424.0 to 1445.0
9 Lower Mannville 1445.0 to 1474.0
10 Banff and Exshaw 1474.0 to 1631.0
11 Wabamun 1631.0 to 1790.0
12 Graminia, Blueridge and Calmar 1790.0 to 1840.0
13 Nisku 1840.0 to 1877.0
14 Ireton 1877.0 to NDE
Wabasca 166, 166A, 166B, 166C, 166D
Item

Column 1

Zone

Column 2

Well Log
Data

00/11-10-81-25W4
Induction Log
(ft.KB)
1 Pelican and Joli Fou 720 to 824
2 Grand Rapids 824 to 1116
3 Clearwater 1116 to 1452
4 Wabiskaw 1452 to 1536
5 McMurray 1536 to 1608
6 Wabamun 1608 to 1677
7 Winterburn 1677 to NDE
White Bear 70
Item

Column 1

Zone

Column 2

Well Log
Data

01/5-15-10-2W2
Neutron Log
(ft.KB)
1 Viking 2670 to 2843
2 Mannville 2843 to 3200
3 Gravelbourg 3200 to 3645
4 Watrous 3645 to 3902
5 Tilston 3902 to 3944
6 Souris Valley 3944 to 4380
7 Bakken 4380 to 4420
8 Torquay 4420 to 4590
9 Birdbear 4590 to 4690
10 Duperow 4690 to 5214
11 Souris River 5214 to 5593
12 Dawson Bay 5593 to 5780
13 Prairie Evaporite 5780 to NDE
White Fish Lake 128
Item

Column 1

Zone

Column 2

Well Log Data

00/14-11-62-13W4note 1m Induction Log (mKB) 00/10-16-62-12W4note 1n Induction Log (mKB)
1 Viking and Joli Fou 347.6 to 386.0 347.0 to 383.5
2 Colony 386.0 to 426.0 383.5 to 397.5
3 Upper Grand Rapids 2 426.0 to 439.0 397.5 to 431.0
4 Lower Grand Rapids 1 439.0 to 453.0 431.0 to 445.0
5 Lower Grand Rapids 2 453.0 to 471.0 445.0 to 459.0
6 Upper Clearwater 471.0 to 498.0 459.0 to 491.5
7 Lower Clearwater 498.0 to 522.0 491.5 to 516.5
8 McMurray 522.0 to NDE 516.5 to 539.5
9 Woodbend   539.5 to NDE
Woodland Cree 226, 227, 228
Item

Column 1

Zone

Column 2

Well Log Data

00/6-18-87-18W5
Sonic Log
(mKB)
00/7-24-86-14W5
Sonic Log
(mKB)
00/9-34-86-17W5
Neutron-Density Log
(mKB)
1 Bullhead surface to 494.0 surface to 475.0 surface to 498.0
2 Debolt 494.0 to 540.0 NP 498.0 to 504.0
4 Shunda 540.0 to 664.0 NP  
5 Pekisko 664.0 to 753.0 475.0 to 518.5  
6 Banff and Exshaw 753.0 to 1051.0 518.5 to 823.0  
7 Wabamun 1051.0 to 1312.0 823.0 to 1078.0  
8 Winterburn 1312.0 to 1397.0 1078.0 to 1205.5  
9 Ireton 1397.0 to 1662.0 1205.5 to 1509.0  
10 Beaverhill Lake 1662.0 to 1700.0 1509.0 to 1566.0  
11 Slave Point 1700.0 to NDE 1566.0 to 1613.5  
12 Granite Wash   1613.5 to 1614.0  
13 PreCambrian   1614.0 to NDE  

SCHEDULE 5

(Subsection 79(1))

Royalties

Interpretation

Definition of marketable gas

1 In this schedule, marketable gas means gas, consisting mainly of methane, that meets industry or utility specifications for use as a domestic, commercial or industrial fuel or as an industrial raw material.

Oil Royalty

Calculation of royalty — oil

2 (1) The royalty on oil that is obtained from, or attributable to, a contract area consists of the basic royalty determined in accordance with subsection (2) or (3), plus the supplementary royalty determined in accordance with subsection (5). All amounts are to be calculated at the time and place of production.

Basic royalty — first five years

(2) During the five-year period beginning on the day on which production of oil from a contract area begins, the basic royalty is calculated in accordance with the table to this subsection on the oil that is obtained from, or attributable to, each well during each month of that period .

TABLE

Item

Column 1

Monthly
Production (m3)

Column 2


Royalty Per Month

1

Less than 80

10% of the number of m3

2

80 to 160

8 m3 plus 20% of the number of m3 in excess of 80

3

More than 160

24 m3 plus 26% of the number of m3 in excess of 160

Basic royalty — subsequent years

(3) Beginning immediately after the period referred to in subsection (2), the basic royalty is calculated in accordance with the table to this subsection on the oil that is obtained from, or attributable to, each well in a contract area during each subsequent month.

TABLE

Item

Column 1

Monthly
Production (m3)

Column 2


Royalty Per Month

1

Less than 80

10% of the number of cubic metres

2

80 to 160

8 m3 plus 20% of the number of m3 in excess of 80

3

More than 160 to 795

24 m3 plus 26% of the number of m3 in excess of 160

4

More than 795

189 m3 plus 40% of the number of m3 in excess of 795

Notice to council

(4) The Minister must send the council notice of the date on which the production referred to in subsection (2) begins.

Supplementary royalty

(5) The supplementary royalty is

(T − B) 0.50 (P − R)

where

and

(T − B) [0.75 (P − R − $12.58) + $6.29]

TABLE

TABLE
Item

Column 1

Reserve

Column 2

Source Producing Before
January 1, 1974

Column 3

Reference Price ($/m3)

1 Pigeon Lake Indian
Reserve No. 138A
Cardium 24.04
Leduc 25.37
2 Sawridge Indian
Reserve No. 150G
Gilwood Sand 25.13
3 Enoch Cree Nation
Reserve No. 135
Lower Cretaceous 24.64
Acheson Leduc 24.45
Yekau Lake Leduc 25.01
4 Sturgeon Lake
Indian Reserve No. 154
Leduc 21.51
5 Utikoomak Lake Indian Reserve No. 155A
Gilwood Sand Unit No. 1 25.00
West Nipisi
Unit No. 1
24.58
6 White Bear Indian
Reserve No. 70
10-2-10-2 W2 well 22.40
8-9-10-2 W2 well 22.63
7 Siksika Reserve No. 146 6-25-20-21 W4 well 18.19
8 Ermineskin Indian
Reserve No. 138
6-11-45-25 W4 well 19.18

Gas Royalty

Calculation of royalty — gas

3 (1) When gas that is obtained from, or attributable to, a contract area is sold, the royalty payable is the gross royalty value of the gas, determined in accordance with subsection (2), less the portion of the cost of gathering, dehydrating, compressing and processing the gas that is equal to its gross royalty value divided by its total value.

Gross royalty

(2) The gross royalty value of gas that is obtained from, or attributable to, a contract area is the basic gross royalty value of 25% of the quantity of that gas multiplied by the actual selling price plus the supplementary gross royalty value determined in accordance with subsection (3). All amounts are to be calculated at the time and place of production.

Supplementary gross royalty

(3) The supplementary gross royalty value of gas, individually determined for each gas component produced, is equal to the sum of the products obtained by multiplying 75% of the quantity of each gas component by

Measurement of volumes

(4) For the purposes of this section, volumes referred to are volumes measured at standard conditions of 101.325 kPa and 15°C.

Notice to council

(5) The Minister must send the council notice of any costs that are deducted under subsection (1) for gathering, dehydrating, compressing and processing.

Royalty on Oil or Gas Consumed

No royalty payable

4 (1) Despite sections 2 and 3, the royalty payable on oil or gas obtained from, or attributable to, a contract area is nil if the oil or gas is consumed in drilling for, producing or processing oil or gas that is obtained from, or attributable to, that contract area.

Royalty payable

(2) However, subsection (1) does not apply to oil or gas that is consumed for the production or processing of crude bitumen.

SCHEDULE 6

(Section 113)

Administrative Monetary Penalties

PART 1
Indian Oil and Gas Act
Item

Column 1

Provision

Column 2

Penalty ($)

1 5(1)(a)(i) 10 000
2 5(1)(a)(ii) 10 000
3 16 10 000
4 17(2) 10 000
PART 2
Indian Oil And Gas Regulations
Item

Column 1

Provision

Column 2

Penalty ($)

1 16 10 000
2 19(2) 1 000
3 21(a)(i) 1 000
4 21(a)(ii) 1 000
5 21(a)(iii) 1 000
6 21(a)(iv) 1 000
7 21(a)(v) 1 000
8 21(b)(i) 1 000
9 21(b)(ii) 1 000
10 21(b)(iii) 1 000
11 21(b)(iv) 1 000
12 21(b)(v) 1 000
13 21(b)(vi) 1 000
14 21(c)(i) 1 000
15 21(c)(ii) 1 000
16 21(c)(iii) 1 000
17 21(c)(iv) 1 000
18 21(c)(v) 1 000
19 21(c)(vi) 1 000
20 21(c)(vii) 1 000
21 21(d)(i) 1 000
22 21(d)(ii) 1 000
23 21(d)(iii) 1 000
24 21(d)(iv) 1 000
25 21(d)(v) 1 000
26 21(d)(vi) 1 000
27 21(d)(vii) 1 000
28 21(d)(viii) 1 000
29 21(e) 1 000
30 21(f) 1 000
31 25(4) 1 000
32 32(1) 2 500
33 32(2)(a) 10 000
34 32(2)(b) 2 500 (per hole)
35 32(2)(c) 2 500
36 32(2)(d) 10 000
37 32(2)(f) 1 500
38 33(1) 10 000
39 34 10 000
40 59(2) 10 000
41 75(5) 10 000
42 78 10 000
43 82(2)(a) 1000
44 82(2)(b) 1000
45 82(2)(d) 1000
46 83(2) 2000
47 98 1 000