Indian Oil and Gas Canada Annual Report 2017 - 2018

Background and Context:

Results Achieved in FY2017 - 2018

An official set (sometimes referred to as the "Blue-Stamped" copy or version) of the Draft Phase I regulations were readied early in Calendar Year 2017. In February 2017, at the request of oil and gas First Nations, further work was put into abeyance until important proposed accommodations could be considered. These accommodations provide First Nations with greater authority and control over their oil and gas resources as well as the ability to customize deals according to their specific business needs. A new set of Blue-Stamped regulations were readied in September 2017. This version addressed some of the concerns raised by oil and gas First Nations and Canada proposed that the remaining issues be addressed as part of the gazetting process.

On February 8, 2018, the JTC passed a unanimous resolution for the IRC to provide written support for the Draft Phase I regulations, including the proposal for their updating during the gazetting process. The IRC Board approved the JTC recommendation at the IRC Board meeting held on March 5, 2018. The next day (March 6, 2018), this was unanimously ratified by IRC member First Nations at the IRC Annual General Meeting. The IRC sent a letter dated March 12, 2018 to the Department confirming their support. As a show of good faith, and to ensure continued close co-operation and collaboration, in early March 2018, the IRC's JTC Program Manager, Mr. David Shade, was asked to represent the IRC, and its membership, as a permanent member of IOGC's MARS Project Steering Committee.

Once it was agreed by all parties that any further accommodations would be made during the gazetting process, the Draft Phase I regulations began departmental approvals. In early FY2018-2019, the approvals process will be presented before Treasury Board for consideration and approval for pre-publication in the Canada Gazette, Part I. The remaining First Nations' accommodations will be made and will appear in the Final Phase I regulations and once again presented to Treasury Board for consideration and approval for publication in Canada Gazette, Part II. Shortly thereafter, both the 2009 Act and the Final Phase I regulations would both become law.

Business Process Modernization

To optimize the benefits to First Nations of the new on-reserve legislative and regulatory regime, its implementation needs to include modernized business practices supported by enhanced informatics. IOGC uses business process mapping / modeling tools to:

• Review existing business practices and processes to ensure synergy and compliance;
• Identify and eliminate duplication of effort; and,
• Reduce red tape and streamline procedures.

Business process modelling and modernization is important because it helps identify the business and user requirements for informatics – new tools, changes needed to existing tools, or identifying data sources that can replace and retire existing ones. It also provides a means of ensuring that IOGC staff continues upgrading their knowledge and expertise of new processes; therefore, allowing them greater responsibility. This benefit results in greater transparency for IOGC's clients and stakeholders.

Informatics Enhancements

A key deliverable in the Informatics Enhancements activities will include an information management activity to document all the business processes that support or are beneficiaries of the enhanced system development.

IOGC's existing Resource Information Management System (RIMS) is the system that stores data concerning all surface and sub-surface agreements, Indian interest wells, and royalty entities. The informatics enhancements that support the implementation of the new Act and regulations are known as the "RIMS2 Project". The RIMS2 Project is a joint initiative between IOGC and the Information Management Branch of Crown-Indigenous Relations and Northern Affairs Canada. In May 2016, the RIMS2 Project received both Project and Expenditure Approvals from Treasury Board.

The proposed RIMS2 Project provides for IOGC membership and data exchange with Petrinex (PETRoleum INformation EXcellence). Petrinex is the result of a unique provincial-industry partnership that created, and which currently operates and maintains, the recognized, authoritative source for hydrocarbon volume and pricing information. IOGC's request for membership in Petrinex was approved in October 2013. Petrinex partners currently include the provinces of Alberta and Saskatchewan as well as the oil and gas industry.

A Memorandum of Agreement (MOA) with the Province of Alberta was drafted and signed in year-end of FY2016-2017.

The proposed RIMS2 Project solution includes:

• Petrinex data exchange with IOGC;
• New Royalty Management functionality; and,
• Introduction of Case Management Capability.

The procurement process began shortly after Treasury Board provided both Project and Expenditure Approvals. A contract by Public Services and Procurement Canada (PSPC) was issued in November 2016 to Fujitsu Consulting Canada Ltd. to begin development work within the Petrinex environment.

Results Achieved in FY2017-2018:

In terms of Petrinex data exchange with IOGC, the project was on target to deliver functionality according to the following forecasted schedule:

1. Access and exchange of Saskatchewan data – June 2018
2. Access and exchange of Alberta data – October 2018
3. Access and exchange of data related to Gas Cost Allowance – January 2019

With respect to both the Royalty Management and the Introduction of Case Management components of the RIMS2 project, a significant project milestone was achieved when the procurement process identified Sierra Systems as the prime contractor for both these components of the RIMS2 project. By the end of Q3, Sierra Systems began progressively assembling a team – located both at IOGC and within their own offices. Workshop sessions with IOGC subject matter experts began in Q4. Initial work focused on the planning for and development of the Royalty Calculation Engine, defining the data needs and sources for data used in the royalty schema's as defined in the leases and the database to support this data.

Results Achieved in FY2017-2018:

IOGC has been working with the JTC on regulations beyond those contained in the Phase I package of regulations for a number of years. Progress has been impacted by limited access to the same subject matter experts required to: 1) finish work on the Phase I regulations and preparing to bring them, together with the 2009 Act, into force; and, 2) organizational readiness activities so IOGC and its staff are prepared to implement and to administer the 2009 Act and Phase I regulations, beginning on the first day they both become law.

Regulatory drafting instructions were shared by IOGC with the JTC for:

1. The Moneys Management module: and,
2. The Surface Tenure module

JTC provided feedback on the Money Management module's proposed regulatory drafting instructions in June 2017 and on the Surface Tenure module's proposed regulatory drafting instructions in December 2017. IOGC continues to meet internally to review the proposed changes and is preparing to respond formally to JTC.

Negotiations, Contracts, and Research Unit

• Identifying disposition options with First Nations;
• Assessing proposals from interested companies to ensure fair return;
• Providing negotiation and facilitation expertise to reach agreements between First Nations and companies;
• Drafting and issuing sub-surface oil and gas agreements;
• Administering sub-surface continuances;
• Monitoring and verifying regulatory and contractual commitments;
• Verifying legal title and status of minerals for surrendered and designated Indian reserve lands prior to disposition; and,
• Providing title verification and confirming acreage for pooling purposes.

The royalty changes that were introduced by the Province of Alberta continue to have an impact on IOGC's operations. The Negotiations, Contracts, and Research Unit continued to review agreements to the extent to which First Nation agreements have been affected by the Alberta royalty regime changes. This review confirmed that there is a continued requirement to dedicate significant resources to ensure these royalty changes are properly reflected in both existing and new agreements issued by IOGC on First Nations reserve lands.

The Negotiations, Contracts, and Research Unit; by working diligently with all stakeholders, was able to continue to implement competitive agreements as compared to provincial royalty regimes. The Negotiations, Contracts, and Research Unit was able to ensure that every new and amended disposition recommended last fiscal year provided a return to First Nations that was higher than both the Alberta and Saskatchewan royalty regimes.

The total number of agreements issued varies from year to year; however, with the impact of the industry slow-down, in FY2017-2018, IOGC issued 10, sub-surface agreements, five less than last year. The total number of these agreements under IOGC administration was 651, comprising 260,897.55 hectares.

In FY2017-2018, IOGC staff performed 702 registrations into the Indian Lands and Registration System (ILRS),this is a major increase from 395 the preceding year. The increase is due to a focused approach to clear a backlog of registrations.

Lease Administration Unit

Issues oil and gas surface leases, rights of way, exploratory licenses, and associated surface rights to companies:

• Administering surface and sub-surface leases;
• Verifying and maintaining corporate information and records; and,
• Registering IOGC transactions in ILRS.

In FY2017-2018, IOGC issued 9 surface agreements. When oil and gas prices are strong, IOGC typically processes between 145-450 agreements in a year.
The current trend is a continued decrease in dispositions as a result of lower commodity prices. During these uncertainties in the economy, due to the downturn of the energy sector, IOGC usually experiences a decrease in requests for new contracts coupled with a substantial increase in assignments and surrenders.

In FY2017-2018, surface land area under disposition amounted to 10,603 hectares. This is a decrease of 29 hectares from the previous year. This number includes new dispositions minus surrendered dispositions. Surface area under disposition refers to the actual amount of reserve land impacted by oil and gas development.

In FY2017-2018, the total number of surface agreements under IOGC administration was 4,948. This is a slight decrease of 29 from the previous year. The total number of agreements varies from year to year. At some point in time, the number of surface leases will decrease as hydrocarbon resources eventually become depleted and sites are reclaimed.

Royalties Unit

IOGC is responsible for verifying and collecting royalty moneys generated by the production and sale of oil and gas resources from First Nations reserve lands. The Royalties Unit is responsible for:

• Ensuring accuracy and completeness of royalty submissions;
• Conducting royalty assessments;
• Managing gas cost allowance deductions;
• Managing trucking deductions; and,
• Monitoring and addressing royalty moneys in suspense.

Geology Unit

IOGC's Geology Unit is responsible for:

• Maintaining annual drilling statistics / summary; and,
• Conducting reviews for the continuation or termination of leases

Drilling on First Nations reserve lands continued to reflect national averages, with a modest increase in wells spudded in FY2017-2018 from the previous year. Industry reported 47 wells drilled on First Nations reserve lands; 28 oil wells, 18 gas wells, one D&A and the remainder reported as steam or water injector wells. 40 drills were licensed as horizontal wells. Additionally, 18 wells were downhole abandoned with all but 6 cut and capped. A total of 181 leases were reviewed as their terms approached expiry. The result was the continuation of 54,502 hectares of land and the termination of 11,425 hectares.

Treaty Land Entitlement (TLE) Support Unit

The TLE Support Unit continues to provide TLE process guidance and oil and gas rights advice to First Nations engaged in Additions to Reserve (ATR) processes as a result of TLE. This Team supports:

• Verification of legal title and disposition information for surface and mineral agreements on status of minerals on designated TLE;
• Drafting and issuance of surface and sub-surface Replacement Agreements (i.e., federal agreements, applicable on reserve lands, to replace existing agreements issued under provincial jurisdiction);
• Ensuring all ATR, specifically TLE stakeholders, are informed and understand IOGC's role in the ATR process.

TLE claims are a type of land claim arising from the fact that some First Nations did not receive all the land they were entitled to under treaties signed with the Federal Crown. Today, the TLE process exists to fulfill these outstanding obligations. TLE often results in an ATR – that is, land is added to a First Nation's reserve lands base – though First Nations can opt to receive other forms of settlement.

One of IOGC's primary roles under the TLE process is to assist with Replacement Agreements for third party interests that existed prior to the lands becoming reserve lands pursuant to a TLE claim. IOGC replaces agreements that are oil and gas-related, typically from provincial title and jurisdiction, which can then be administered according to the Indian Oil and Gas Act and its regulations once the lands become reserve lands under federal title.

Special Subject: Band-Owned Oil and Gas Companies

Many First Nations are no longer passive recipients of oil and gas royalties from their natural resources. In fact, they are becoming more involved in the oil and gas operations on their lands. First Nations have created Band-owned oil and gas companies (BOCs). The structure of each BOC can be different for every First Nation as it reflects their desired level of participation and their community goals. A BOC provides a First Nation with greater control, additional economic rent, and an opportunity for capacity building.

At the end of FY2017-2018, there were 17 BOCs holding 173 sub-surface agreements comprising 67,911 hectares (26% of all lands managed by IOGC) of First Nations reserve lands.

Environment Team

IOGC provides environmental stewardship for the complete lifecycle of upstream oil and gas activities on First Nations reserve lands.

Before approval is granted to a company to conduct surface oil and gas activity, a thorough environmental review is completed. The types of activities that require an environmental review include exploratory or seismic work, drilling for oil and gas, flow lines, service wells, remediation and access roads. The Environment Team ensures that potential environmental impacts are mitigated before IOGC and the First Nation approve the application.

After construction of surface facilities and sites, industry compliance with environmental requirements is monitored during their operation. The Team reviews environmental audits that companies are required to submit and also perform field inspections when necessary. The 2017-2018 fiscal year was especially challenging for field inspections due to the increase in industry bankruptcies and insolvencies as IOGC endeavoured to perform additional inspections on those sites to ensure they were left in a safe and secure manner.

After operations of a surface facility or site have ceased, companies must abandon wells, remove facilities, conduct remediation if necessary, and reclaim the area. The Environment Team approves the surrenders of surface agreements following confirmation, by inspection with First Nation representatives, that reclamation is satisfactory.

Compliance and Enforcement

• Providing litigation support, including assisting Justice Canada and the departmental Litigation Management Resource Branch (LMRB) with legal actions;
• Establishing a strategy for Compliance and Enforcement Framework: Ensuring readiness for implementation when the Indian Oil and Gas Act, 2009 and the Phase I regulations come into force;
• Monitoring quality assurance of instruments that have compliance / enforcement impacts.

Resource Analysis and Compliance

• Maintaining well files on all newly-drilled wells;
• Managing trespass and potential drainage situations, including enforcement;
• Preparing revenue forecasts;
• Conducting ongoing and routine engineering and geology work including review of notices and applications.

The Resource Analysis and Compliance unit has two main goals – the first is to support conservation of the oil and gas resources of First Nations and the second is to provide First Nations with information forecasting oil and gas activity and projected revenues from such activity on their reserve lands. The unit strives to provide a high level of service to First Nations related to its assigned functions.

One of its most important functions is to conduct drainage monitoring and issue drainage notices. To carry out this function, the unit monitors off-reserve wells producing close to reserve boundaries. Each of these situations is reviewed to determine whether or not drainage may be occurring. Where IOGC believes that drainage may be occurring, and where the relevant on-reserve lands are leased, the relevant First Nation's band council is contacted so that a joint determination of potential drainage may be made. Once such a determination is made, IOGC will prepare and issue a drainage notice to the relevant lessee(s) of the reserve lands in consultation with the band council. If the Unit believes that drainage may be occurring yet the adjacent reserve lands are not leased, then IOGC's Negotiations, Contracts, and Research Unit and the First Nation are advised so that any opportunities for leasing the reserve lands can be investigated.

Technical Business Support Unit

The Technical Business Support (TBS) Unit contributes to the Regulatory Compliance Directorate mandate by:

• Initiating and coordinating production and royalty-related audits, examinations, investigations and inspections to ensure safe and appropriate field operations and a fair return to First Nations for the development of their resources;
• Collaborating and coordinating research with respect to technical, economic and regulatory issues;
• Supporting IOGC, other Government of Canada bodies, First Nations and provincial agencies.

The TBS unit responds to many and varied requests from IOGC business units, First Nations, other government agencies, and the oil and gas industry. These requests include: modifications to royalty structures; consideration of financial issues; coordination and collaboration in federal and provincial initiatives; support for specific claims; investigation into existing and emerging issues; provision of technical data, information, and advice to support royalty assessment; and, initiating and supporting compliance actions.

During FY2017-2018 TBS staff conducted several field inspections for the purposes of ensuring safe operations and complying with oil and gas production measurement, allocation, and reporting requirements. The TBS Unit responded to two requests for royalty changes, concluded one special investigation while initiating three more, and recommended changes to provincial directives as a result of its investigations.

Oil Production from First Nations Reserve Lands

Crude oil is found in geological formations hundreds or thousands of metres deep in the subsurface of the earth. Most of the formations appear to be "solid rock" but they contain oil in generally very small openings (called "pore spaces") within the otherwise solid-looking rock formations. The oil also contains natural gas dissolved in it, like the gases that appear in soda pop when a bottle cap is removed. When the oil is produced, the gas "bubbles out" of the oil as it rises to the surface and even more gas "bubbles out" as the oil is treated and stored at the surface.

During FY2017-2018, oil was produced from 32 reserves belonging to 25 First Nations. The oil production history chart indicates that oil production from First Nations reserve lands decreased by about 16% compared to the previous year. Total First Nations oil production in FY2017-2018 was approximately 674,000 cubic metres, down from 807,000 the year before. As in previous years, most of the oil produced from First Nations is heavy oil.

The majority of FY2017-2018 oil production, approximately 65%, came from First Nations in Saskatchewan, about the same percentage as FY2016-17. As in past years, it is worth noting that over 90% of Saskatchewan First Nation oil production comes from just one First Nation.

Description of of figure A: History of Oil Production from First Nations reserve lands, 2008-2009 to 2017-2018

This graph shows Oil Production from First Nation Lands from fiscal year (FY) 2008-09 through fiscal year 2017-2018.

During FY 2008-09, 697 thousand cubic metres of oil were produced from First Nations in western Canada:

• 496 thousand cubic metres (71.1%) from Alberta First Nations;
• 201 thousand cubic metres (28.8%) from Saskatchewan First Nations; and
• 432 cubic metres (0.1%) from British Columbia First Nations.

During FY 2009-10, 719 thousand cubic metres of oil were produced from First Nations in western Canada:

• 443 thousand cubic metres (61.7%) from Alberta First Nations; and
• 275 thousand cubic metres (38.3%) from Saskatchewan First Nations.

During FY 2010-11, 1.01 million cubic metres of oil were produced from First Nations in western Canada:

• 552 thousand cubic metres (54.6%) from Alberta First Nations; and
• 458 thousand cubic metres (45.4%) from Saskatchewan First Nations.

During FY 2011-12, 1.18 million cubic metres of oil were produced from First Nations in western Canada:

• 666 thousand cubic metres (56.3%) from Alberta First Nations; and
• 518 thousand cubic metres (43.7%) from Saskatchewan First Nations.

During FY 2012-13, 1.11 million cubic metres of oil were produced from First Nations in western Canada:

• 658 thousand cubic metres (59.6%) from Alberta First Nations;
• 446 thousand cubic metres (40.3%) from Saskatchewan First Nations;
• 3 cubic metres were reported as produced from British Columbia First Nations; and
• 87 cubic metres (less than 0.01%) from one Manitoba First Nation.

During FY 2013-14, 925 thousand cubic metres of oil were produced from First Nations in western Canada:

• 538 thousand cubic metres (58.2%) from Alberta First Nations;
• 387 thousand cubic metres (41.8%) came from from Saskatchewan First Nations; and
• 398 cubic metres (0.04%) came from the one First Nation in Manitoba.

During FY 2014-15, oil and gas companies produced 790 thousand cubic metres of oil from First Nations in western Canada:

• 473 thousand cubic metres (60%) from Alberta First Nations; and
• 317 thousand cubic metres (40%) from Saskatchewan First Nations.

That fiscal year, IOGC did not receive oil production data from First Nations in British Columbia, nor from Manitoba First Nations. The one company that had reported modest oil production in Manitoba during the previous fiscal years, shut in their wells during FY 2014-15.
During FY 2015-16, 737 thousand cubic metres of oil were produced from First Nations in western Canada:

• 402 thousand cubic metres (54.5%) from Alberta First Nations; and
• 335 thousand cubic metres (45.5%) came from Saskatchewan First Nations.

During FY 2016-17, over 806 thousand cubic metres of oil were produced from First Nations in western Canada:

• 513 thousand cubic metres (63.7%) from Saskatchewan First Nations; and
• 293 thousand cubic metres (36.3%) from First Nations in Alberta.

Note that, in this fiscal year, for the first time, oil production from Saskatchewan First Nations exceeded oil produced from Alberta First Nations.
During FY 2017-18, almost 674 thousand cubic metres of oil were produced from First Nations in western Canada. Again this year, Saskatchewan First Nations produced more oil than Alberta First Nations:

• 440 thousand cubic metres (65.3%) came from Saskatchewan First Nations; while
• 234 thousand cubic metres (34.7%) came from First Nations in Alberta.

Oil production continues to decrease, year to year, from a total peak of almost 1.2 million cubic metres in fiscal year 2011 to 2012, to 674 thousand cubic metres in FY 2017-2018. The exception was an increase to 802 thousand cubic metres in 2016 to 2017, but the decline resumed in 2017-2018.

Oil Prices

As reported in previous years, prices for oil, natural gas and natural gas products fluctuate according to a wide variety of influences. Canadian prices are influenced principally by North American markets, US drilling and production levels, and US crude oil inventories. Yet they also feel the effects of geo-politics and geo-economics.

However, during the latter part of FY2017-2018, the price of heavier Canadian crude oils – most of the oil production from First Nations has characteristics between heavy oil and bitumen – dropped disproportionately while prices for lighter crude oils rose. This gave rise to the serious concerns expressed over "the differential" between higher light crude prices – exemplified by West Texas Intermediate (WTI) oil - and lower heavy crude prices – in this case, Western Canada Select (WCS).

The reasons for the price differential usually stem from the differences in oil density (called "gravity") and other characteristics, like sulphur content, acid content and the presence of other contaminants, as well as routine pipeline, storage and dilution costs.

In the latter part of FY2017-2018, other factors came to bear. For example, some refineries in the US were shut in for maintenance or upgrading and there were pipelines which suffered temporary breakdowns or were also upgraded. This led to a glut of heavy oil in Canada, which has no other market or transportation options, and a severe depression of prices.

So a "normal" differential of approximately $10 to $12 US per barrel ballooned to as high as $30 per barrel. This created such concerns in industry, government and First Nations, that provincial and federal government agencies have become active, all searching for a solution. Perhaps one or more solutions can be found during FY2018-2019, or thereafter.

Once again, oil and gas producing companies, as well as oilfield service companies, are facing difficult financial circumstances. Several have gone out of business, cut back capital expenditures and other operations or have been acquired by competitors. This year, as in the past few years, most industry experts believe that oil prices will not reach 2014 price levels, for example, for many years, if ever.

Meanwhile, the following graph indicates that average prices for First Nations' oil continue to track between heavy oil prices and bitumen prices. This is appropriate because the "average" First Nation oil has properties that place it between those oil varieties.

Description of figure B: History of First Nation Weighted Average Oil Prices versus Benchmark Prices, 2013-2014 to 2017-2018

Oil prices generally increased over fiscal year (FY) 2017-2018, due to changes in crude oil inventories world-wide and various geopolitical influences. Canadian Light Sweet oil (in other words, sweet oil prices at Edmonton) rose 13%, finishing at $457.70 per cubic metre in March 2018. That was actually the highest price experienced in FY 2017-2018.

Meanwhile, the Alberta Bitumen Floor price, which is the Government of Alberta's price limit and used for their royalty calculations, and which is considered to be an indicator of crude bitumen prices, rose 70%, finishing in March 2018 at $180.16 per cubic metre.

Unfortunately, due mostly to North American pipeline constraints, Western Canada Select oil prices, an indicator of heavy oil prices, did not fare as well throughout the year. At first, they, too rose. From April 2017 to November 2017, they increased 17% to peak at $365.29 per cubic metre. But pipeline disruptions caused the price to drop to $288.93 per cubic metre by March 2018. As of this writing, however, they have rebounded.

As explained in past annual reports, based on data received from companies that produce oil on First Nation lands, IOGC calculates what we call a "weighted average First Nation crude oil price". IOGC admits that the weighted average price is somewhat "artificial" in nature, but that price still provides both an estimate of value received, and an indication of the overall average characteristics of the various crude oils produced from First Nations.

During FY 2017-18, the weighted average First Nations price for crude oil indicates once again how the "average" First Nation oil is similar to heavy oil, with influences from bitumen pricing behavior. That is because most First Nation crude oil is produced from heavy oil / bitumen areas.

Thus, the average First Nation oil price also rose early in FY 2017-18. In April 2017, that average price was just over $267.62 per cubic metre. It rose to $319.38 by November 2017, but then declined to $234.34 per cubic metre in March 2018. However, similar to Western Canada Select prices, discussed above, the average First Nation oil price has also rebounded since then.

The average prices for First Nation oil continue to track between heavy oil prices and bitumen prices. That is appropriate because the "average" First Nation oil has properties that place it between heavy oil and bitumen.

Natural Gas Production from First Nations Reserve Lands

Natural gas, as with oil, also comes from geological formations hundreds or thousands of metres down in the subsurface. Again, the formations appear to be "solid rock" but they contain natural gas in small pores spaces within the otherwise solid-looking rock formations. Some formations contain only natural gas and, occasionally, some contain natural gas plus some associated products, like ethane, propane, butane, and even some hydrocarbon liquids. As mentioned earlier, natural gas can also originate in subsurface formations that contain oil. In the oil-bearing formations, the gas is dissolved in the oil. When the oil is produced, the gas "bubbles out" of the oil in the subsurface and at the surface as the oil is treated and stored.

During fiscal year FY2017-2018, natural gas was produced from 49 reserves belonging to 35 First Nations. The natural gas production history chart indicates that natural gas sales from First Nations reserve lands, in contrast to the declining oil production described above, increased by about 11% from FY2016-17. Total First Nation gas production was just above 1.7 billion cubic metres. The vast majority of Indian interest gas is still produced from Alberta First Nations, slightly over 98%.

It's worth noting that the production of natural gas liquids (NGLs) in FY2017-2018 increased by about 37% over FY2016-2017. This is slightly disproportionate to the 11% natural gas production increase mentioned above. Natural gas and natural gas liquid production declined on Saskatchewan First Nation lands, but increased on Alberta First Nation lands. This indicates that companies will continue to drill for natural gas and the more lucrative accompanying natural gas liquids even in times when natural gas prices are very low. Otherwise, they prefer to drill for oil.

Description of figure C: History of Natural Gas Sales from First Nations, 2008-2009 to 2017-2018

This graph shows Oil Production from First Nation Lands from fiscal year (FY) 2008-2009 through fiscal year 2017-2018.

During FY 2008-2009, 697 thousand cubic metres of oil were produced from First Nations in western Canada:

• 496 thousand cubic metres (71.1%) from Alberta First Nations;
• 201 thousand cubic metres (28.8%) from Saskatchewan First Nations; and
• 432 cubic metres (0.1%) from British Columbia First Nations.

During FY 2009-2010, 719 thousand cubic metres of oil were produced from First Nations in western Canada:

• 443 thousand cubic metres (61.7%) from Alberta First Nations; and
• 275 thousand cubic metres (38.3%) from Saskatchewan First Nations.

During FY 2010-2011, 1.01 million cubic metres of oil were produced from First Nations in western Canada:

• 552 thousand cubic metres (54.6%) from Alberta First Nations; and
• 458 thousand cubic metres (45.4%) from Saskatchewan First Nations.

During FY 2011-2012, 1.18 million cubic metres of oil were produced from First Nations in western Canada:

• 666 thousand cubic metres (56.3%) from Alberta First Nations; and
• 518 thousand cubic metres (43.7%) from Saskatchewan First Nations.

During FY 2012-2013, 1.11 million cubic metres of oil were produced from First Nations in western Canada:

• 658 thousand cubic metres (59.6%) from Alberta First Nations;
• 446 thousand cubic metres (40.3%) from Saskatchewan First Nations;
• 3 cubic metres were reported as produced from British Columbia First Nations; and
• 87 cubic metres (less than 0.01%) from one Manitoba First Nation.

During FY 2013-2014, 925 thousand cubic metres of oil were produced from First Nations in western Canada:

• 538 thousand cubic metres (58.2%) from Alberta First Nations;
• 387 thousand cubic metres (41.8%) came from from Saskatchewan First Nations; and
• 398 cubic metres (0.04%) came from the one First Nation in Manitoba.

During FY 2014-2015, oil and gas companies produced 790 thousand cubic metres of oil from First Nations in western Canada:

• 473 thousand cubic metres (60%) from Alberta First Nations; and
• 317 thousand cubic metres (40%) from Saskatchewan First Nations.

That fiscal year, IOGC did not receive oil production data from First Nations in British Columbia, nor from Manitoba First Nations. The one company that had reported modest oil production in Manitoba during the previous fiscal years, shut in their wells during FY 2014-2015.

During FY 2015-2016, 737 thousand cubic metres of oil were produced from First Nations in western Canada:

• 402 thousand cubic metres (54.5%) from Alberta First Nations; and
• 335 thousand cubic metres (45.5%) came from Saskatchewan First Nations.

During FY 2016-2017, over 806 thousand cubic metres of oil were produced from First Nations in western Canada:

• 513 thousand cubic metres (63.7%) from Saskatchewan First Nations; and
• 293 thousand cubic metres (36.3%) from First Nations in Alberta.

Note that, in this fiscal year, for the first time, oil production from Saskatchewan First Nations exceeded oil produced from Alberta First Nations.

During FY 2017-2018, almost 674 thousand cubic metres of oil were produced from First Nations in western Canada. Again this year, Saskatchewan First Nations produced more oil than Alberta First Nations:

• 440 thousand cubic metres (65.3%) came from Saskatchewan First Nations; while
• 234 thousand cubic metres (34.7%) came from First Nations in Alberta.

Oil production continues to decrease, year to year, from a total peak of almost 1.2 million cubic metres in fiscal year 2011 to 2012, to 674 thousand cubic metres in FY 2017-2018. The exception was an increase to 802 thousand cubic metres in 2016 to 2017, but the decline resumed in 2017-18.

Natural Gas Prices

There are currently no other market options at present, therefore, Canadian natural gas producers must continue to compete for the Canada and US market share against the prolific US natural gas field developers who have greater access to transportation infrastructure with less resistance to expansion. During early FY2017-2018, natural gas prices dropped dramatically, causing some operators to shut in their production and others to sell gas properties or even go out of business. The natural gas price history chart indicates that the average FY2017-2018 First Nation natural gas prices, along with the benchmark prices they are compared to, dropped to the near-record lows of approximately $1.00 per gigajoule experienced previously, near the end of FY2015-2016. Prices rallied slightly near the end of FY2017-2018 but they still remain very low for Canadian producers. The somewhat higher prices quoted in the media every day do not reflect what Canadian producers get, it only reflects what American producers get because, among other factors, their fields are closer to their markets.

Description of figure D: History of First Nation Weighted Average Sales Gas Prices versus Benchmark Prices, 2013-2014 to 2017-2018

Fiscal year (FY) 2017-18 was not a good year for natural gas prices for western Canadian producing companies or royalty owners. In September and October 2017, due to varied pipeline expansion and maintenance programs , pipeline access was restricted so severely that prices briefly became "negative". In other words, some producers appeared to be paying their customers to take their natural gas. That negative price environment was unprecedented in natural gas production and pipeline history and came at a time during the year when producers are normally shipping large volumes to utilities and other companies, so that gas can be stored in underground formations in anticipation of the upcoming winter season, and then produced back and sold to consumers.

In an effort to reduce surplus shipping volumes, companies stopped drilling for natural gas, some temporarily shut their wells in, and some tried to purchase natural gas storage in Alberta (to save gas for later, when prices might rise), to reduce the "revenue bleeding". Several announced that they would be actively searching for different sales and transportation options for future production.

Meanwhile, producers in the United States enjoyed rising prices because of their adequate transportation infrastructure and more varied export options.

The negative price environment was over by November 2017, which is the beginning of the annual "heating season" and the target date for the completion of all pipeline expansion and maintenance projects. Prices rose to approximately $2.00 per gigajoule in November but began to taper down to the range of $1.50 per gigajoule (the Alberta Reference Price, reflective of natural gas contract prices and used by Alberta in the calculation of royalties) to $1.92 per gigajoule for natural gas sales on the shorter-term spot market.

Like crude oil, based on data received from companies producing natural gas on First Nation lands, IOGC also calculates a "weighted average First Nation natural gas price". It also provides an estimate of value and an indication of whether First Nation natural gas prices follow market prices. During FY 2017-18, that weighted average price for natural gas began at $2.62 per gigajoule, then declined to $0.79 per gigajoule in October 2017, then rose as high as $1.97 in January 2018. The weighted average price then declined slightly, like the other natural gas price benchmarks, and finished March 2018 at $1.85 per gigajoule. When compared to the beginning of the fiscal year, the price had decreased by just over 29%. Unfortunately, the price continued to decline into FY 2018-19.

Policy Unit

Regulatory Compliance's Policy Unit is responsible for:

• Advising on strategic policy;
• Researching and developing operational policy;
• Monitoring and preparing responses to Parliament on changes to provincial regimes; and,
• Consulting on operational and strategic policy changes.

The Policy Unit's primary focus has been the development of new regulations. The Department adopted a phased approach for regulations development designed to have the 2009 Act become law sooner than if a full set of regulations were completed. This approach ensures that First Nations will benefit sooner from the improvements embodied within the IOGA, 2009 which provides new authority for IOGC in the following areas to:

• Audit companies working on First Nations reserve lands;
• Determine and advise industry of longer records retention time for auditing purposes;
• Deal more effectively with surface and sub-surface trespass;
• Protect First Nation sites of cultural importance;
• Order companies to take remedial action under certain circumstances; and,
• Issue fines and penalties for offences under the Act or regulations.

Furthermore, the phased approach will require updates to the Indian Oil and Gas Regulations, 1995 – ensuring they are in congruence with the IOGA, 2009 – including new regulations in the areas of:

• Drainage and Compensatory Royalty;
• Sub-surface Tenure;
• First Nations' Audit (a component of Royalty Management);
• Reporting Requirements to Facilitate Royalty Verification.

The remaining regulatory modules will become law once they are completed and, at the end of the process, IOGC will have jurisdiction to oversee and enforce a complete set of new, modern regulations. In consideration of the time required to accommodate input from stakeholders and the government's regulations review and approval process, it is projected that the 2009 Act and its regulations will come into force in 2019. The Policy Unit spent much of the year working on the new regulations while consulting, engaging, and informing First Nations. Throughout the regulations development process, upon request, face-to-face meetings have taken place with individual First Nations, Tribal Councils, and Treaty Areas, as well as with the Joint Technical Committee (JTC) and at the Indian Resource Council (IRC) Annual General Meeting where updates were presented.

Contracts and Administration Unit

• Contract and procurement services;
• Material management services;
• Office administration, accommodation and tenant services;
• Security services;
• Information Management, records and, resource library and Access to Information and Privacy Act (ATIP) services.

Finance Unit

• Corporate financial services;
• Resource planning;
• Trust fund administration;
• Accounts payable;
• Accounts receivable.

Human Resources Unit

• Human resources planning and reporting;
• Employee recruitment;
• Staff relations and workplace well-being;
• Compensation and benefits;
• Training and career development;
• Classification and organizational development;
• Human resources policy development;
• Official languages.

Planning, Administrative Policy and Corporate Coordination Unit

• Annual IOGC Management Plan;
• Quarterly reporting;
• IOGC inputs into INAC plans and reports;
• IOGC Co-Management Board secretariat services;
• Implementing corporate-wide departmental and government directed initiatives and administrative policy development;
• Occupational Safety and Health (OSH).

Information Technology Unit

• Database administration;
• Technical support to application development, RIMS1 Steering Committee governance;
• Distributed computing including end user support (via call centre), hardware and software management;
• Shared Services Implementation;
• IT security;
• Technical support for video-conferencing, smart-boards and rollout of other HQ technology and systems.

Revenues Collected on Behalf of First Nations

During FY2017-2018, IOGC received $62.6 million on behalf of First Nations. This included $49.3 million as a result of oil and gas royalties, $991,688 in bonuses, $12.0 million in compensation and rentals, $208,054 in royalties from Treaty Land Entitlement 5.08 lands, and $13,224 in interest.^{Footnote 3}

2017-18 Total Moneys Collected on Behalf of First Nations ($Millions)

Description of figure E: History of Moneys collected on behalf of First Nations FY2007-2008 to FY2017-2018

This chart shows royalty revenues ($ millions) received from oil and gas that IOGC collected on behalf of First Nations. The graph shows total monies collected during 11 consecutive fiscal years from FY2007-2008 to FY2017-2018.

• 2007-2008: Oil $47.76; Gas/Production $133.25; Land $16.20; Treaty Land Entitlement 5.08 Lands $5.14
• 2008-2009: Oil $70.04; Gas/Production $146.79; Land $29.73; Treaty Land Entitlement 5.08 Lands $7.89
• 2009-2010: Oil $63.56; Gas/Production $39.78; Land $13.31; Treaty Land Entitlement 5.08 Lands $9.17
• 2010-2011: Oil $95.69; Gas/Production $43.44; Land $75.27; Treaty Land Entitlement 5.08 Lands $42.04
• 2011-2012: Oil $145.39; Gas/Production $43.56; Land $29.26; Treaty Land Entitlement 5.08 Lands $35.33
• 2012-2013: Oil $94.02; Gas/Production $26.91; Land $36.48; Treaty Land Entitlement 5.08 Lands $19.04
• 2013-2014: Oil $93.26; Gas/Production $30.72; Land $27.60; Treaty Land Entitlement 5.08 Lands $5.90
• 2014-2015: Oil $75.15; Gas/Production $62.12; Land $24.20; Treaty Land Entitlement 5.08 Lands $1.65
• 2015-2016: Oil $23.96; Gas/Production $23.06; Land $15.64; Treaty Land Entitlement 5.08 Lands $0.315
• 2016-2017: Oil $20.37; Gas/Production $25.01; Land $13.95; Treaty Land Entitlement 5.08 Lands $0.26
• 2017-2018: Oil $21.23; Gas/Production $28.09; Land $13.03; Treaty Land Entitlement 5.08 Lands $0.208

Human Resources at IOGC

IOGC is committed to ensuring a safe and healthy work environment where all staff are valued and treated with respect, dignity and fairness.

At IOGC, we fully recognize that our people make our organization what it is. We are proud of our diverse workforce and our employment equity representation levels which exceed labour market availability. Tremendous synergy results when differing viewpoints, skill sets, and experiences are brought together. IOGC employees are professional and bring their best to the achievement of our organization's mandate, vision, and values.

IOGC strives to be a workplace of choice and this is an essential spoke on our Strategic Wheel (see following page). IOGC believes in being a learning organization and each employee has a personal annual learning plan. There is a tuition reimbursement program for those employees pursuing professional development outside of work hours. IOGC offers in-house French language training, soft skills training (which in 2017 – 2018 focused on workplace well-being and mental health), and annual Indigenous Cultural Awareness training. IOGC also has an Employee and Family Assistance program.

IOGC actively promotes work-life balance and utilizes flexible hours of work and telework, as approved through the IOGC Telework Policy. Our Pride and Recognition program is used to reward employee achievements and recognize staff with long-term service. IOGC maintains its own Committee for the Advancement of Native Employees (CANE).

IT – Resource Information Management System 1

IOGC's existing Resource Information Management System (RIMS1) is the operational database that stores information regarding all surface and sub-surface agreements, Indian interest wells, and royalty entities. It supports the departmental trust fund management system with both land and royalty financial transaction records that help IOGC verify that First Nations receive the proper royalties that are due. During 2017-2018, work was initiated to upgrade RIMS1 to Oracle 12.

A new RIMS2 is under development for royalty management using Petrinex data exchange and case management tools. RIMS2 will replace only the royalty module of the current RIMS.

Figure F: Excellence in managing First Nation oil and gas resources

Description of figure F: Excellence in managing First Nation oil and gas resources

IOGC Strategic Framework is an illustration in pie chart format which details the organization's vision and key elements required for IOGC to achieve its aim of becoming a modern regulator. The chart is divided into four main organizational goals which each represent a quarter of the circle including: Excellence in Governance, Excellence in Oil and Gas Management, Effective Relationships and Workplace of Choice. Each quarter of the circle is then further explained and broken down into their respective parts.

Excellence in Governance

Excellence in Oil and Gas Management

Workplace of Choice

Effective Relationships