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,

• The lack of a consistent set of rules that are different from rules off reserves has made investment in oil and gas projects on reserves less attractive, as industry has had to employ duplicative processes and systems — one for their on-reserve projects and another for their projects in the rest of the province.
• It is challenging to regulate the full range of modern oil and gas development activities on First Nation reserve lands due to limited regulatory enforcement mechanisms. In addition, the 1995 Regulations lack a compliance and enforcement regime, which means that the main recourse for addressing any violation of the rules is to cancel contracts.

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:

• Under the existing Act and regulations, Canada does not have the necessary enforcement tools to encourage industry compliance and to take appropriate action to address non-compliance. Indian Oil and Gas Canada has limited options to address non-compliance: cancelling a lease or court action.
• Existing operational practices and schedules related to data collection and royalty calculation are misaligned with those of the oil- and gas-producing provinces. The impact for some companies deciding to invest on First Nation reserve lands is that they have to develop duplicate processes and systems for reporting their oil and gas activities on reserve lands, separate from those for reporting their activities off reserves. The need to duplicate efforts represents an administrative burden and is a disincentive to companies considering investment on First Nation reserve lands.

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

• To ensure compatibility with the IOGA, 2009.
• To reflect modern regulatory drafting conventions.
• To reflect current practices and procedures that have evolved over years of working in partnership with Indian Oil and Gas Canada, First Nations, industry and the provinces and that have proven beneficial to regulating oil and gas activity on First Nation reserve lands, such as the environmental review process.
• To address comments provided as a result of reviews by the Standing Joint Committee for the Scrutiny of Regulations.

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

• Ensure that First Nations and industry have a predictable regulatory environment in which to make investment decisions.
• Provide for 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.

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

• (a) Establish procedures for: the issuance of licences and terms and conditions those of licences to explore lands for potential oil and gas; subsurface contracts that allow oil and gas production; surface contracts for accessing subsurface interests; and the determination of the length of the initial term for both permits and leases. These changes would subject stakeholders to regulated, rather than negotiated, procedures and terms.
• (b) Introduce rule sets for the earning provisions on permits and for the continuation of contracts. The introduction of provisions in the proposed Regulations explaining how additional lands are earned under a permit, and outlining the circumstances under which a contract is continued after its initial term, are significant steps in ensuring that First Nations and industry have a predictable operating environment.
• (c) Introduce record-keeping and reporting requirements for a wide range of data, including information required to enhance the accuracy of royalty assessments and payments; data on the likelihood of oil and gas production potential; and progress reports on oil and gas development activities. These changes would align data reporting and gathering with that of the provinces. Once supporting informatics enhancements have been completed, Canada would use the same system as the provinces and could automatically extract the data it needs and industry would no longer need to maintain duplicate processes and systems for their on- and off-reserve projects.
• (d) Broaden the option of the electronic submission of data and issuance of notices. This would bring the regime closer to the standards and processes of its more modern and efficient counterparts within the provinces.
• (e) Establish when compensatory royalty is owed where First Nation reserve lands are drained of their oil and gas by drilling in adjoining areas. This change is rooted in existing provincial drainage laws, thus ensuring consistency with the off-reserve system, but also including modifications to address concerns regarding the uniqueness of First Nation reserve land boundaries.

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

• (a) Add a process by which First Nations may arrange to conduct an audit, on behalf of the Minister of Indian Affairs and Northern Development, of the activities of those engaged in oil and gas exploration and development on their lands. Modernization of the regime includes addressing the perspectives of many stakeholders. This provision represents a means for First Nations to become more involved in ensuring that the compliance and enforcement regime is robust and flexible.
• (b) Remove the provision by which the decisions of the Executive Director of Indian Oil and Gas Canada may be reviewed by the Minister of Indian Affairs and Northern Development, as under the IOGA, 2009, all decisions are made by the Minister. The increasing complexity of regulating industry activities means that redress mechanisms also required updating and modernization. The ministerial review of Executive Director decisions has proven to be an unnecessary step, since these disputes are usually taken to the courts. This particular change ensures that, when a stakeholder is not in agreement with a decision of the Minister, the issue can be addressed by a court with competencies in the area of oil and gas operations in a timelier manner.
• (c) Establish administrative penalties for specified violations of the Act and regulations. A modern suite of regulatory tools, including a schedule of violations, to encourage industry compliance and to appropriately address situations of non-compliance would improve Canada's ability to regulate oil and gas development on First Nation reserve lands. Upon coming into force, the Act and the proposed Regulations will provide authority to audit, to issue shutdown and remedial action orders, as well as to inspect, search and seize in a manner consistent with the off-reserve regime.
• (d) Ensure all applications for oil and gas surface activities include an environmental review to ensure activities are undertaken without causing irremediable damage to First Nation reserve lands. Providing that environmental reviews are performed prior to the drilling of every well is a key aspect of ensuring Canada establishes a regulatory environmental regime that is consistent and compatible with the regulatory environmental regime off reserves, and that First Nation sites of cultural, historical and ceremonial significance are preserved.

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 codification of procedures for the issuance of licences, as well as surface and subsurface contracts, and transparent terms and conditions for these contracts, replacing the need to negotiate the terms of each specific agreement.
• The provision of defined rule sets for the earning provisions on permits and for the continuation of contracts, replacing the need to negotiate the terms of each specific agreement.
• The establishment of record-keeping and reporting requirements for a wide range of data, including information required to enhance the accuracy of royalty assessments and payments, data required to support the continuance application of a subsurface contract, plus a one-time continuance application requirement.
• The introduction of the electronic submission of data and issuance of notices, to eliminate the requirement for industry to maintain duplicate systems and processes for their on-reserve projects.

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:

For French inquiries:

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

• (a) in respect of oil, the price at which the oil is sold; and
• (b) in respect of gas, the price or consideration payable that is specified in the gas sales contract, free of any fees or deductions other than transport charges after departure from the facility outlet. (prix de vente réel)

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

• (a) an angle of at least 80°, measured between the line extending from the initial point of penetration into the target zone and the end point of the wellbore in that zone to the line extending vertically downward from the initial point of penetration into that zone; and
• (b) a minimum length of 100 m, measured from the initial point of penetration into the target zone to the end point of the wellbore in that zone. (tronçon horizontal)

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

• (a) the costs of completion, in the case of a well that has been drilled but not completed; or
• (b) the costs of production, in the case of a well that has been completed. (productif)

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

• (a) they are a corporation that is authorized by the law of the relevant province to carry on business in that province or an individual who has reached the age of majority in that province;
• (b) they are not in default under subsection 111(5); and
• (c) in the case of a corporation, neither it nor any of its directors, officers or agents or mandataries has been convicted of an offence under subsection 18(2) of the Act within two years preceding the date of the bid in the case of a grant by public tender or the date of the application in the case of a negotiated contract.

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:

• (a) comprehensive general liability insurance that covers the risks of damage resulting from operations to be carried out under the contract with an inclusive bodily injury, death and property damage limit of at least $5 000 000 per occurrence, including occupier's liability or liability for damage caused by immovables, employer's liability, employer's contingent liability, contractual liability, contractor's protective liability, products liability, completed operations liability and contractor's liability insurance;
• (b) automobile liability insurance that covers all vehicles used in operations carried out under the contract with an inclusive bodily injury, death and property damage limit of at least $5 000 000 per occurrence; and
• (c) if aircraft are to be used in operations carried out under the contract, aircraft liability insurance with an inclusive bodily injury, death and property damage limit of at least $10 000 000 per occurrence.

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

• (a) acknowledges liability for any damage resulting from operations to be carried out under the contract; and
• (b) declares that their financial resources are adequate to cover their liabilities.

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

• (a) prepared in accordance with the Canada Lands Surveys Act;
• (b) approved by the Surveyor General of Canada; and
• (c) recorded in the Canada Lands Survey Records.

Exception

(2) Subsection (1) does not apply to

• (a) an exploration work survey plan; or
• (b) a survey of lands that are added to a reserve under a treaty land entitlement agreement or a specific claim settlement agreement.

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

• (a) an additional bonus is paid, if necessary, to reflect the fair value, determined in accordance with section 38, of the interests or rights granted by the amendment; and
• (b) additional surface rates are paid, if necessary, in accordance with subsections 73(2) and (3).

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:

• (a) before the day on which the well is spudded,
  • (i) a copy of the provincial licence authorizing the drilling of the well and the licence application,
  • (ii) the drilling and coring plan proposed for the well,
  • (iii) the geological prognosis,
  • (iv) any proposed horizontal drilling plan, and
  • (v) a copy of the surface lease survey plan;
• (b) within 30 days after the day on which the well is rig-released,
  • (i) all daily drilling reports for the period beginning on the day on which the rig move begins and ending on the day of rig-release,
  • (ii) a copy of each wireline log prepared,
  • (iii) the results of any drill-stem test conducted,
  • (iv) a copy of the final downhole well drilling survey, if one is required by the provincial authority,
  • (v) any description, test or analysis resulting from an identification of any well sections that were cored, and
  • (vi) a copy of the geological report, if one is required by the provincial authority;
• (c) within 30 days after the day on which the well is completed,
  • (i) all daily completion reports and the final downhole well schematic,
  • (ii) a copy of each wireline log prepared,
  • (iii) any core and fluid analyses prepared,
  • (iv) any swab reports prepared,
  • (v) the results of any pressure or flow tests conducted, including the results of any surface casing vent flow test,
  • (vi) a hydraulic fracturing fluid component information disclosure report, and
  • (vii) a detailed report of any downhole well intervention or stimulation;
• (d) within 30 days after the day on which any recompletion or workover of the well is completed,
  • (i) all daily recompletion or workover reports,
  • (ii) a copy of each wireline log prepared,
  • (iii) any core and fluid analyses prepared,
  • (iv) any swab reports prepared,
  • (v) the results of any pressure or flow tests conducted, including the results of any surface casing vent flow test;
  • (vi) a hydraulic fracturing fluid component information disclosure report,
  • (vii) a detailed report of any downhole well intervention or stimulation, and
  • (viii) the final downhole well schematic;
• (e) within 30 days after the day on which the well is downhole-abandoned, all daily operation reports relating to the downhole abandonment; and
• (f) within 30 days after the day on which the well is surface-abandoned, all daily operations reports of the cut and cap operation and a copy of the final abandonment report submitted to the provincial authority.

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

• (a) if the holder also holds a subsurface lease or permit in lands in the licence area, the day on which the lease expires or is continued, the initial term of the permit expires or, in the case of a permit issued under the Indian Oil and Gas Regulations, 1995, the permit is converted to one or more leases, and
• (b) the fifth anniversary of the day on which the exploration work is completed.

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

• (a) confidential information to a council if required to do so by the Act, any regulations made under the Act or a contract; and
• (b) the results of an environmental review referred to in subsection 29(3), 57(2) or 75(2) to a council or the public.

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

• (a) it is conditional;
• (b) it would result in more than five persons having an interest or rights in the contract;
• (c) it assigns an undivided interest or rights in the contract that are less than 1%;
• (d) it divides the oil and gas rights conferred by the contract;
• (e) the assignee is not eligible under section 6; or
• (f) the assignment was not signed by the assignor and assignee.

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

• (a) the Indian Act, and any orders made under that Act, as amended from time to time;
• (b) the Act, and any regulations or orders made under the Act, as amended from time to time; and
• (c) the laws of the relevant province, as amended from time to time, that relate to the environment or to the exploration for or the exploitation, treatment or conservation of oil and gas, including equitable production, if those laws are not in conflict with the Act or any regulations or orders made under the Act.

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

• (a) hold an exploration licence;
• (b) have obtained from the provincial authority any permission that is required to carry out exploration work in the province; and
• (c) are in compliance with the terms of the licence and the permission.

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

• (a) the terms negotiated with the council;
• (b) if the permission of the provincial authority is required to carry out exploration work, a statement that the permission has been received;
• (c) a description of the proposed exploration program, including the area to be included in the licence, the exploration work to be carried out, the equipment to be used, the name of the geophysical contractor to be engaged and the anticipated duration of the work;
• (d) the results of an environmental review of the proposed exploration program that has been conducted by a qualified environmental professional who deals with the applicant at arm's length; and
• (e) the exploration licence application fee set out in Schedule 1.

Environmental review

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

• (a) a site evaluation that is based on the site's topography, soils, vegetation, wildlife, sources of water, existing structures, archeological and cultural resources, traditional ecological knowledge, current land uses and any other feature of the site that could be affected by the proposed exploration program;
• (b) a description of the operations to be carried out during the proposed exploration program, the duration of each and its location on the site;
• (c) a description of the short-term and long-term effects that each operation could have on the environment of the site and on any surrounding areas;
• (d) a description of the proposed mitigation measures, the potential residual effects after mitigation and the significance of those effects; and
• (e) a description of the consultations undertaken with the council and reserve residents.

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

• (a) any surface rights granted under an Act of Parliament; and
• (b) any right to explore for or exploit minerals other than oil or gas in the licence area.

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

• (a) ensure that all environmental protection measures included in the licence are implemented and complied with;
• (b) identify and mark the location of every test hole and shot hole that has been drilled under the licence;
• (c) repair and recondition any roads or road allowances that are damaged as a result of the exploration work as soon as the circumstances permit after the damage occurs;
• (d) as soon as the circumstances permit, plug any hole that is drilled under the licence and that, during or after completion of the exploration work, collapses or emits gas, water or another substance;
• (e) within 90 days after the day on which the exploration work is completed, pay compensation for the exploration work that was carried out, based on the rates specified in the licence or a related subsurface contract; and
• (f) within 90 days after the day on which the exploration work is completed, submit to the Minister and the council
  • (i) a mylar sepia copy and a legible paper copy of a map, on a scale of not less than 1:50 000, that shows the location and ground elevation of every vibrating equipment station, shot hole and test hole,
  • (ii) summaries of any geologist's and driller's logs, indicating the depth and thickness of formations bearing water, sand, gravel, coal and other minerals of possible economic value, and
  • (iii) all technical information obtained from the drilling of each test hole.

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),

• (a) a copy of every aerial photograph taken during the period of exploration;
• (b) two copies of a geological report on the explored area, including stratigraphic data and structural and isopach maps on a scale of not less than 1:50 000; and
• (c) a geophysical report on the area explored.

Content of geophysical report

(3) The geophysical report must include

• (a) if seismic work has been carried out,
  • (i) a mylar sepia copy and two legible paper copies of a map, on a scale of not less than 1:50 000, that shows contour lines drawn on the corrected time value at each source point for all significant reflecting horizons explored, with a contour line interval of not more than 10 m,
  • (ii) a mylar sepia copy and two prefolded paper copies of each stacked seismic cross-section, including migrated displays if that process has been carried out, with all significant reflecting horizons clearly labelled at both ends on one of the copies, and
  • (iii) two microfilm copies of all basic recorded data, including survey notes, chaining notes and observer reports;
• (b) if a gravity survey has been carried out, two legible copies of a map, on a scale of not less than 1:50 000, that shows the location and ground elevation of each station, the final corrected gravity value at each station and gravity contour lines drawn on that value with a contour line interval of not more than 2.5 µm/s²; and
• (c) if a magnetic survey has been carried out, two legible copies of a map of the area, on a scale of not less than 1:50 000, that shows the location of the flight lines or grid stations and magnetic contour lines, with a contour line interval of not more than 5 nT.

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

• (a) if the holder also holds a subsurface lease or permit in lands in the licence area, 90 days after the day on which the lease expires or is continued, the initial term of the permit expires or, in the case of a permit issued under the Indian Oil and Gas Regulations, 1995, the permit is converted to one or more leases; and
• (b) one year after the day on which the exploration work is completed.

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:

• (a) an oil and gas permit;
• (b) an oil and gas lease.

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:

• (a) the size of the other lands and their proximity to the First Nation lands;
• (b) the time when the rights in the other lands were granted;
• (c) current oil and gas prices and the prices when the rights were granted;
• (d) the results of recent drilling operations in the vicinity of the other lands;
• (e) similarities and differences in the geological features of the other lands and the First Nation lands;
• (f) any other factors that could affect the fair value of the interests or rights.

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:

• (a) the type of subsurface contract to be granted;
• (b) the terms of the contract, other than those set out in these Regulations, or the address of a website where the terms are set out, including
  • (i) a description of the lands to be included in the contract area and the oil and gas rights to be granted,
  • (ii) the surface rates and seismic rates,
  • (iii) the initial and intermediate terms of the permit or the term of the lease, as the case may be,
  • (iv) in the case of a permit, the earning provisions for the initial term, including the drilling commitment and deadline for completion, the target zone or depth to which each earning well must be drilled and the lands to be earned by each, and
  • (v) the royalty to be paid, if it differs from the royalty provided for in these Regulations;
• (c) the instructions for submitting a bid, including any information to be provided by bidders, the place where a bid may be submitted and the deadline for submission; and
• (d) a statement indicating that the bidder acknowledges that they have reviewed and understood the terms of the contract to be granted and will be bound by those terms if theirs is the winning bid.

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

• (a) in a publication known to the industry, such as the Daily Oil Bulletin published by the June Warren-Nickle's Energy; or
• (b) on a website on which the Minister publishes information about oil and gas in First Nation lands.

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

• (a) the subsurface contract application fee set out in Schedule 1;
• (b) the rent for the first year of the contract;
• (c) the bonus; and
• (d) the name and address for service of each proposed contract holder and the percentage share of each.

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:

• (a) the type of subsurface contract to be granted;
• (b) a description of the lands to be included in the contract area and the oil and gas rights to be granted;
• (c) the terms of the contract, other than those set out in these Regulations;
• (d) the elements that will be considered in evaluating the proposals;
• (e) a statement that the proposals that are received will form the basis for negotiations with the council and the Minister; and
• (f) a statement that in addition to the terms negotiated, the contract will include the terms set out in these Regulations.

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:

• (a) the type of subsurface contract to be applied for;
• (b) a description of the lands to be included in the contract area and the oil and gas rights to be granted;
• (c) the amount of the bonus to be paid;
• (d) the initial and intermediate terms of the permit or the term of the lease, as the case may be;
• (e) in the case of a permit, the earning provisions for the initial term, including the drilling commitment and deadline for completion, the target zone or depth to which each earning well must be drilled and the lands to be earned by each; and
• (f) the royalty to be paid, if it differs from the royalty provided for in these Regulations.

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

• (a) the lands and oil and gas rights described in the application have been surrendered or designated under section 38 of the Indian Act; and
• (b) the proposed bonus reflects the fair value of the rights to be granted, determined in accordance with section 38 of these Regulations.

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:

• (a) a written resolution of the council approving the terms of the contract and stating that the council has chosen to have the rights described in the contract granted by way of negotiation rather than public tender;
• (b) the bonus and first year's rent; and
• (c) two original copies of the contract — as well as an original copy for each future contract holder — all of which are signed by each of them.

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,

• (a) drilled a new well in the permit area; or
• (b) re-entered an existing well in the permit area and drilled at least 150 m of new wellbore.

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

• (a) be contiguous, if their configuration permits; and
• (b) include the entire spacing unit in which the earning well is located.

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

• (a) if the permit has terminated under subsection 52(2), the application must be submitted within 15 days after the day of termination; or
• (b) if the deadline for applying has been extended under subsection 62(2), the application must be submitted before the extension expires.

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

• (a) an identification and description of each well that has been drilled and each well that has been re-entered and completed;
• (b) a description of the lands, including the zones, selected for the intermediate term of the permit; and
• (c) the rent for the first year of the intermediate term.

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

• (a) approve the selection of lands if the requirements of section 52 are met; and
• (b) grant the holder the oil and gas rights in the selected lands for the intermediate term of the permit if the holder has complied with the requirements of the Act, these Regulations and their permit.

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

• (a) one well is drilled on each section in the reserve that is in the area of the proposed bitumen recovery project and at least 25% of those wells are cored; or
• (b) one well is drilled on at least 60% of the sections in the reserve that are in the area of the proposed bitumen recovery project, at least 25% of those wells are cored and seismic data are obtained over at least 3.2 km in each undrilled section.

Content of application

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

• (a) a description of the lands to be included in the project;
• (b) evidence establishing that the minimum level of evaluation has been achieved;
• (c) a statement that the holder has applied for or received the provincial authority's approval of the project;
• (d) the results of an environmental review of the project that has been conducted by a qualified environmental professional who deals with the holder at arm's length;
• (e) the terms respecting the royalty to be paid for the oil and gas obtained from lands in the project area;
• (f) the reporting requirements for the project;
• (g) a detailed description of the project, including its location, size and scope, the operations to be carried out, the schedule of pre-construction, construction and start-up operations and the reasons for selecting that schedule;
• (h) a map indicating all the interests and rights in the lands in the project area and in any area that is likely to be affected by project operations;
• (i) an aerial photographic mosaic of the project area at a scale that is adequate to show the location of the project components, including wells, facilities, tanks, access roads, railways, pipelines, public utility corridors, tailings ponds and waste storage sites;
• (j) a detailed description of storage and transportation facilities for the oil and gas, including the size of any pipeline that may be used and the name of the entity that owns it;
• (k) the anticipated rate of production of the oil and gas for the period for which approval is sought;
• (l) the year and month in which the minimum level of production will be achieved;
• (m) a description of the energy sources to be used and their anticipated quantity and cost, along with a comparison to alternative sources; and
• (n) the term of the approval sought, along with the anticipated starting and completion dates of the project.

Environmental review

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

• (a) a site evaluation that is based on the site's topography, soils, vegetation, wildlife, sources of water, existing structures, archeological and cultural resources, traditional ecological knowledge, current land uses and any other feature of the site that could be affected by the project;
• (b) a description of all operations to be carried out during the project, their duration and their location on the site;
• (c) a description of the short-term and long-term effects that each operation could have on the environment of the site and on any surrounding areas;
• (d) a description of the proposed mitigation measures, the potential residual effects after mitigation and the significance of those effects; and
• (e) a description of the consultations undertaken with the council and reserve residents.

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

• (a) the applicant has achieved the minimum level of evaluation of the lands in the project area;
• (b) a written resolution of the council approving the project has been submitted;
• (c) the application meets the requirements of subsections 57(1) and (2);
• (d) the project has been approved by the provincial authority; and
• (e) the project can be carried out without causing irremediable damage to the First Nation lands.

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

• (a) the holder has spudded or re-entered a well for the purpose of deepening it or completing a new zone, but cannot finish the operation before the relevant term expires;
• (b) the application is submitted before the relevant term expires;
• (c) the application identifies the well and indicates when it was spudded or re-entered; and
• (d) the application includes the rent for the following year.

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

• (a) that contains a productive well;
• (b) that is subject, in whole or in part, to a unit agreement that includes lands in which a productive well is located, or to an oil or gas storage agreement that has been approved by the provincial authority;
• (c) that is subject to a bitumen recovery project that has been approved by the Minister;
• (d) that is subject to a project, other than a bitumen recovery project, that has been approved by the provincial authority and includes lands in which a productive well is located;
• (e) in respect of which an offset notice has been received in the six months before the day on which the application for continuation is submitted or in respect of which a compensatory royalty is being paid;
• (f) that is not producing but is shown by mapping to be potentially capable of producing from the same pool from which a well on an adjoining spacing unit is productive; or
• (g) that is potentially productive.

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

• (a) it contains a well that is in a mapped pool, is neither productive nor abandoned and
  • (i) was previously producing, or
  • (ii) contains evidence of the presence of hydrocarbons whose potential productivity has not been conclusively determined;
• (b) it contains an abandoned well and any zone penetrated by the well has remaining oil or gas reserves; or
• (c) it has not been drilled, there is evidence that it may be part of a productive pool and it is within a quarter-section in the case of oil — or a section in the case of gas — that adjoins any lands referred to in paragraphs (1)(a) to (e).

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

• (a) a description of the lands, including the zones, with respect to which continuation is sought;
• (b) an indication of the basis for continuation under subsection 63(1) along with evidence establishing that basis; and
• (c) the rent for the first year of the continuation.

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

• (a) $2 000; and
• (b) $400 for each full or partial legal subdivision or, if the lands have not been divided into legal subdivisions, $400 for each unit of land equivalent to 16 hectares, rounded up to the nearest whole number of units.

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

• (a) the council asks the Minister to do so in a written resolution sent to the Minister that describes the lands, including the zones, to which the request relates and the requested period of continuation;
• (b) a request for continuation under this subsection has not previously been made in respect of those lands;
• (c) the written consent of the holder is sent to the Minister;
• (d) the resolution and consent are sent within 30 days after the day on which the notice referred to in subsection 65(5) is received; and
• (e) the holder has paid the rent for the first year of the continuation.

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

• (a) the council asks the Minister to do so in a written resolution sent to the Minister that describes the lands, including the zones, to which the request relates and the requested period of continuation;
• (b) a request for continuation under this subsection has not previously been made in respect of those lands;
• (c) the written consent of the holder is sent to the Minister;
• (d) the resolution and consent are sent within 30 days after the day on which the continuation granted under subsection 65(4) expires; and
• (e) the holder has paid the rent for the first year of the continuation.

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:

• (a) a description of the lands, including the zones, with respect to which the contract is eligible for continuation;
• (b) the basis for continuation; and
• (c) the requirements for an application for continuation, as well as the deadline for submission.

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,

• (a) the project terminates on the final day of that year; and
• (b) the contract expires on the final day of that year, unless it is continued under subsection (3).

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

• (a) in the case of operations that require crossing over or going through First Nation lands, they hold a right-of-way in those lands; and
• (b) in the case of operations that require the exclusive occupation and use of the surface of First Nation lands, they hold a surface lease in respect of those lands.

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:

• (a) the lands to be included in the contract area;
• (b) the operations that will be carried out on those lands;
• (c) the surface rates, if they have not already been fixed by the Minister in a related subsurface contract; and
• (d) if a service well is to be drilled or an existing well is to be used as a service well, the permitted uses of the well and the amount of compensation to be paid in respect of the well.

Surface rates — right-of-way

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

• (a) a right-of-entry charge of $1 250 per hectare, subject to a minimum charge of $500 and a maximum charge of $5 000; and
• (b) initial compensation based on the fair value of lands that are similar in size, character and use.

Surface rates — surface lease

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

• (a) the right-of-entry charge referred to in paragraph (2)(a);
• (b) initial compensation based on the fair value of lands that are similar in size, character and use, the loss of use of the lands, adverse effects and general disturbance; and
• (c) the annual rent for subsequent years, based on the loss of use of the lands and adverse effects.

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

• (a) the terms negotiated with the council and any First Nation member in lawful possession of lands in the contract area;
• (b) a survey plan of the lands to be included in the contract area;
• (c) the results of an environmental review of the operations to be carried out in the contract area that has been conducted by a qualified environmental professional who deals with the applicant at arm's length; and
• (d) the surface lease or right-of-way application fee set out in Schedule 1.

Environmental review

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

• (a) a site evaluation that is based on the site's topography, soils, vegetation, wildlife, sources of water, existing structures, archeological and cultural resources, traditional ecological knowledge, current land uses and any other feature of the site that could be affected by the proposed uses of the lands in the contract area;
• (b) a description of all operations to be carried out on the lands, the duration of each and the location of each on the site;
• (c) a description of the short-term and long-term effects that each operation could have on the environment of the site and on any surrounding areas;
• (d) a description of the proposed mitigation measures, the potential residual effects after mitigation and the significance of those effects; and
• (e) a description of the consultations undertaken with the council and reserve residents.

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

• (a) the terms negotiated with the council and any First Nation member in lawful possession of lands in the contract area; and
• (b) the environmental protection measures that must be implemented to permit the holder to carry out operations under the contract.

Submission to Minister

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

• (a) four original copies of the contract, signed by the applicant;
• (b) a written resolution of the council approving the contract and the written consent of any First Nation member in lawful possession of lands in the contract area; and
• (c) the right-of-entry charge and initial compensation owed under the contract.

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

• (a) every five-year period; and
• (b) any period fixed by the laws of the relevant province for the renegotiation of surface leases in respect of off-reserve lands.

Lease to be amended

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

• (a) a written resolution of the council approving the renegotiated rent is submitted along with the written consent of any First Nation member in lawful possession of lands in the lease area; and
• (b) the Minister determines the renegotiated rent is fair on the basis of the criteria mentioned in paragraph 73(3)(c).

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:

• (a) the volume and quality of the oil or gas produced, sold, acquired or stored, or to which a right was acquired, by that person during the month in which the oil or gas was produced;
• (b) the value for which the oil or gas, or a right to the oil or gas, was sold or acquired;
• (c) any costs and allowances to be taken into account in determining the royalty payable on the oil or gas; and
• (d) any other information that is required to calculate or verify the royalty payable.

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:

• (a) a signed copy of any written sales contract, or if the contract was unwritten, a document that sets out its terms;
• (b) a transaction statement, invoice or other document that sets out the details of the transaction; or
• (c) any agreement between persons respecting the costs and allowances to be taken into account in determining the royalty payable on the oil or gas.

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

• (a) its council has entered into an audit or examination agreement with the Minister; and
• (b) the audit or examination is conducted in accordance with the agreement and these Regulations.

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,

• (a) must not be employed by, be affiliated with or represent any oil or gas company;
• (b) must have the certifications and comply with the occupational health and safety requirements required or imposed by the holder of the contract or by law; and
• (c) must keep confidential any documents or information they obtain in connection with the audit or examination and must comply with the security requirements imposed by the holder of the contract or by law.

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

• (a) the name of the person whose documents and information are to be audited or examined;
• (b) the name and location of each facility in which the audit or examination will be conducted and the name of the facility's operator;
• (c) the type of audit or examination to be conducted;
• (d) the period to be covered by the audit or examination;
• (e) the anticipated dates for starting and completing the audit or examination;
• (f) the reasons why the council believes the audit or examination is necessary; and
• (g) a statement indicating whether the council is prepared to cover the costs of the audit or examination.

Decision

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

• (a) the reasons provided by the council for conducting the proposed audit or examination do not establish the existence of a risk that warrants an audit or examination;
• (b) within the three years before the date of the application, the requested type of audit or examination has been conducted under the Act in respect of the same contract for the same period and the holder was found to be in compliance with the contract, these Regulations and the Act;
• (c) the proposed audit or examination is not on the Minister's list of priority audits or examinations and the council is not prepared to cover its costs; or
• (d) the Minister and the council do not agree on the proposed type of audit or examination, the period to be covered or the dates for starting and completion.

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:

• (a) the name of the proposed auditor or examiner;
• (b) a detailed audit or examination plan;
• (c) the dates for starting and completing the audit or examination;
• (d) the name of any person who will accompany the proposed auditor or examiner and a description of their role in the audit or examination; and
• (e) evidence establishing that the proposed auditor or examiner has the credentials and experience referred to in subsection 86(1).

Refusal

91 The Minister may refuse the request if

• (a) the information required by section 90 has not been provided;
• (b) a requirement referred to in section 86 has not been complied with; or
• (c) one or more reasons for which preliminary approval of the audit or examination was given have changed.

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

• (a) the 90th day after that day, if the offset notice is not sent until after confidential information about the well is made public;
• (b) the day on which an extension of the offset notice expires, if one has been given under paragraph 5(1)(d) of the Act; or
• (c) the 180th day after that day, in any other case.

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

• (a) send the council a notice of the triggering well;
• (b) send an offset notice to any person that becomes a holder of a subsurface lease in those lands; and
• (c) send an offset notice to any person that becomes a holder of a permit in those lands one year after the effective date of the permit.

Information included in notice

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

• (a) the name of the subsurface contract holder, the contract number and the holder's percentage share in the contract;
• (b) a description of the lands in the contract area that are subject to the notice;
• (c) the unique well identifier of the triggering well;
• (d) the percentage interest or right of the First Nation in the relevant off-reserve spacing unit;
• (e) a description of the off-reserve spacing unit in which the triggering well is located and the offset zone;
• (f) in the case of a horizontal or multilateral triggering well, the total length of the well, the total length of the horizontal section of the well and the length of the section of the well that is producing from the off-reserve spacing unit;
• (g) in the case of a deviated well that is producing from more than one spacing unit, the total length of the well and the length of the section of the well that is producing from the off-reserve spacing unit;
• (h) the offset period; and
• (i) statements indicating that
  • (i) a spacing unit from which a triggering well is producing adjoins the First Nation spacing unit in the contract area described in paragraph (b),
  • (ii) the obligation to pay a compensatory royalty begins on the first day of the month following the day on which the offset period ends,
  • (iii) the compensatory royalty must be paid on or before the 25th day of the third month after the month in which the oil or gas from the triggering well is produced, and
  • (iv) the obligation to pay the compensatory royalty ends in any of the circumstances referred to in subsection 100(1).

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:

• (a) the triggering well is not draining from the offset zone referred to in the offset notice;
• (b) the offset zone of the triggering well has been abandoned, as shown in the records of the provincial authority;
• (c) an offset well is producing from the offset zone;
• (d) the spacing unit from which the triggering well is producing no longer adjoins the First Nation spacing unit referred to in the offset notice;
• (e) the offset zone in the First Nation spacing unit is subject to a unit agreement under which oil or gas is being or is deemed to be produced;
• (f) the triggering well is subject to a storage agreement that has been approved by the provincial authority.

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

• (a) in the case of a vertical triggering well or deviated triggering well that is producing from a single spacing unit an amount equal to the amount that would have been payable by the holder as a royalty in that month if the triggering well were producing from the First Nation spacing unit; and
• (b) in the case of a horizontal triggering well, multilateral triggering well or deviated triggering well that is producing from more than one spacing unit, an amount equal to the percentage of the amount referred to in paragraph (a) calculated in accordance with the formula

(L⁄T) × 100

where

• L is the length of the section of the triggering well that is located in the adjoining off-reserve spacing unit and is capable of producing oil or gas from the offset zone; and
• T is the total length of the section of the well that is capable of producing oil or gas.

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

• C is the amount of the compensatory royalty calculated in accordance with subsection (1); and
• I is the percentage interest or right of the First Nation in the off-reserve spacing unit.

Calculation of compensatory royalty

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

• (a) the volume of oil, gas or condensate to be used in the royalty formula is the volume of oil, raw gas or condensate that was produced in the month by the triggering well, as shown by the records of the provincial authority; and
• (b) the price to be used is
  • (i) in the case of oil, in Saskatchewan, the price indicated in the Monthly Crude Oil Royalty/Tax Factor History published by the Ministry of the Economy and, in the other provinces, the monthly par price for light, medium, heavy or ultra heavy oil, as the case may be, published by Alberta's Department of Energy,
  • (ii) in the case of gas, in Saskatchewan, the price indicated in the Monthly Natural Gas Royalty/Tax Factor History published by the Ministry of the Economy and, in the other provinces, the Gas Reference Price in the monthly information letter Natural Gas Royalty Prices and Allowances published by Alberta's Department of Energy, and
  • (iii) in the case of condensate, the Pentanes Plus Reference Price in the monthly information letter Natural Gas Royalty Prices and Allowances published by Alberta's Department of Energy.

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

• (a) establishes any of the circumstances set out in subsection 96(1); or
• (b) surrenders 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 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

• (a) if the holder sends the Minister a notice establishing a circumstance referred to in subsection 96(1), on the first day of the month in which the Minister receives the notice; or
• (b) if the holder has surrendered their rights, on the first day of the month following the month in which the Minister receives a notice of the surrender.

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:

• (a) a description of the well;
• (b) a detailed description of the proposed uses of the well and any related facilities; and
• (c) the bonus and the annual compensation to be paid for any disposal rights.

Approval

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

• (a) the application is made in accordance with subsection (2);
• (b) the approval of the council has been obtained; and
• (c) the approval will benefit the relevant First Nation.

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,

• (a) all the rights or interests in a spacing unit must be surrendered; and
• (b) the rent for subsequent years is reduced in proportion to the reduction of the lands, to a minimum of $100.

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

• (a) the holder is not in default under the contract, these Regulations or an order given under the Act;
• (b) the Minister and the council have inspected the area of the contract to be surrendered and the Minister has confirmed that the remediation and reclamation of the surface in that area is satisfactory; and
• (c) in the case of a partial surrender, the boundaries of the remaining contract area continue to meet the requirements of these Regulations and the fee for partial surrender approval set out in Schedule 1 has been paid.

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

• (a) within 30 days after the day on which the notice is received, submit to the Minister an amended plan that corrects the deficiencies identified in the notice; and
• (b) remedy the non-compliance identified in the notice sent under subsection (1) in accordance with that plan.

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 138A^{note 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 138A^{note 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

• (a) in respect of oil to which subsection (2) applies, the amount determined by the formula

(T − B) 0.50 (P − R)

where

• T is the amount of oil, in m³, that is obtained from, or attributable to, each well in a contract area during the month,
• B is the basic oil royalty, in m³, calculated in accordance with subsection (2) or (3),
• P is the actual selling price of the oil per m³, and
• R is the reference price, equal to
  • (i) in the case of oil obtained from a source set out in column 2 of the table to this subsection, the amount set out in column 3, and
  • (ii) in any other case, $25 per m³;

and

• (b) in respect of oil to which subsection (3) applies, the amount determined by the formula

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

• where
• T is the amount of oil, in m³, that is obtained from, or attributable to, each well in the contract area during the month,
• B is the basic oil royalty, in m³, calculated under subsection (2) or (3),
• P is the actual selling price of the oil per m³, and
• R is the reference price, equal to
  • (a) in the case of oil obtained from a source set out in column 2 of the table to this subsection, the amount set out in column 3, and
  • (b) in any other case, $25 per cubic metre.
    

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

• (a) in the case of marketable gas,
  • (i) if the actual selling price exceeds $10.65/10³ m³ but does not exceed $24.85/10³ m³, 30% of the difference between the actual selling price per 10³ m³ and $10.65/10³ m³, or
  • (ii) if the actual selling price exceeds $24.85/10³ m³, $4.26/10³ m³ plus 55% of the portion of the actual selling price in excess of $24.85/10³ m³;
• (b)) in the case of pentanes plus, if the actual selling price exceeds $27.68 / m³, 50% of the portion of the actual selling price in excess of $27.68 / m³;
• (c)) in the case of sulphur, if the actual selling price exceeds $39.37 / t, 50% of the portion of the actual selling price in excess of $39.37 / t;
• (d)) in the case of other components from a source that produces marketable gas, an amount equal to the product obtained by multiplying the actual selling price of each of those components by the percentage by which the overall royalty rate for marketable gas, taking both basic and supplementary gross royalty values into account, exceeds 25%; and
• (e) in the case of other components from a source that does not produce marketable gas, the lesser of one third of the actual selling price of that component and the amount determined under any special agreement entered into under subsection 4(2) of the Act.
  

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