Indian Oil and Gas Canada (IOGC) Annual Report 2018-2019

History of Indian Oil and Gas Canada and the Legal Authorities Under Which It Operates

The Government of Canada has a broad mandate for First Nation issues, which arises from existing legislation and from legal obligations contained in section 91(24) of the Constitution Act, 1867. Crown-Indigenous Relations and Northern Affairs Canada (CIRNAC)^Footnote1is entrusted with fulfilling various obligations of the federal government to Indigenous people as outlined in the Constitution, treaties, the Indian Act, and other legislation. Included in this obligation is the management of natural resources on First Nations lands, including oil and gas.

Oil and gas development on First Nations lands has been legislated since 1974 under the Indian Oil and Gas Act, 1974. Prior to that, oil and gas activities were administered under the Indian Act. In 1977, the Indian Oil and Gas Regulations were promulgated and brought under the Indian Oil and Gas Act, 1974. Those regulations were last revised in 1995.

In 1987, Indian Oil and Gas Canada (IOGC) was established and replaced Indian Minerals West within the Department of Indian Affairs and Northern Development^Footnote1. IOGC’s mandates are to manage oil and gas development on First Nations lands and to further First Nation initiatives to manage and control their resources. In 1993, IOGC became a Special Operating Agency to increase its client focus. IOGC reports to CIRNAC via the Assistant Deputy Minister of Lands and Economic Development.

Statutory Authorities

IOGC operates in accordance with provisions of the Indian Oil and Gas Act, 1974 and the Indian Oil and Gas Regulations, 1995.

IOGC also operates in accordance with other federal legislation including provisions of the Indian Act, the Canadian Environmental Assessment Act, 2012^Footnote2, and the Financial Administration Act.

IOGC Co-Management Board

IOGC operates under the direction of an Executive Director and Chief Executive Officer (CEO) who participates as a member of the IOGC Co-Management Board. The Board was established in 1996 by the signing of a Memorandum of Understanding between the Minister of Indian Affairs and Northern Development and the Indian Resource Council (IRC – an Indigenous organization that advocates on behalf of approximately 189 member First Nations with oil and gas or the potential for such resources). The Board focuses on areas of common interest.

There are nine members on the IOGC Co-Management Board. The Board is comprised of the IRC Chair and five other members nominated by the IRC. Two positions are named government official positions: the Assistant Deputy Minister of Lands and Economic Development; and, the Executive Director and CEO of IOGC. One position is appointed by the Minister from the oil and gas industry.

Roles and Responsibilities

IOGC is a Special Operating Agency and separate employer within Crown-Indigenous Relations and Northern Affairs Canada with responsibility for managing and regulating oil and gas resources on designated^Footnote3First Nations lands across Canada.

Over 500 reserves have lands designated, pursuant to the Indian Act, for oil and gas development. At present, 194 companies have active oil and gas agreements on First Nations lands. IOGC currently manages the oil and gas resources of 57 First Nations (108 reserves) with active oil and gas agreements. All funds collected on behalf of First Nations are placed in their trust accounts.

IOGC works closely with First Nation Chiefs and Councils through the negotiation and approval processes. All agreements require Chief and Council approval through a band council resolution (BCR). For those First Nations who have designated their lands for oil and gas activities; IOGC’s main functions are to:

• Facilitate the negotiation and granting, and the ongoing administration of contracts among First Nations and oil and gas companies;
• Conduct environmental reviews and issue environmental protection measures;
• Monitor and verify oil and gas production and sales prices;
• Verify / assess and collect moneys such as bonuses, royalties, and rents;
• Lifecycle management, including well, pipeline and facility compliance monitoring throughout all phases as well as abandonments, remediation and reclamation; and,
• Ensure legislative and contract requirements are satisfied.

Key Project #1 – Indian Oil and Gas Act, 2009 (IOGA, 2009) and Phase I Regulations Implementation

Since this has been a multi-year effort, it is important to provide some important historic background and context.

Key Project #2 – Resource Information Management System 2 (RIMS2)

Results Achieved in FY2018-2019:

In terms of the new Royalty Management functionality:

• During Q1, the 14 royalty calculation mechanisms needed for active leases in Saskatchewan had been identified, completed, and had passed acceptance testing while work had begun on the 44 mechanisms identified in Alberta;
• In Q2, design work on the Gas Cost Allowance module had been completed to support a possible implementation date in Q4; and,
• In February 2019, a major project milestone was reached when the new Gas Cost Allowance (GCA) capability was developed and deployed, as planned and scheduled. IOGC's clients and stakeholders will be using this new feature for the next period for their GCA reporting and the new tools and processes are expected to facilitate and streamline reporting.

With respect to both the Royalty Management and the Introduction or Piloting of Case Management components of the RIMS2 project, workshop sessions with IOGC subject matter experts began in Q4 the previous fiscal year. The 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. This work led to the development of a prototype Royalty Calculation Engine. The RIMS2 Project is forecasted to be completed in FY2020-2021.

Key Project #3 – Phase II Regulations Development

A staggered or phased approach to regulations development means that regulations will be progressively developed and brought into force until the existing 1995 Regulations have been entirely replaced by new, modern regulations.

Operations

IOGC has four directorates that administer and manage the exploration and development of oil and gas resources on First Nations lands:

1. Executive
2. Lease and Royalty Administration
3. Regulatory Compliance
4. Planning and Corporate Services

Special Subject: Province of Alberta’s Announced Crude Oil Production Curtailment

On December 2, 2018, the Government of Alberta announced a temporary curtailment of crude bitumen and crude oil production that will start on January 1, 2019. According to the province, Alberta produced more crude oil in 2018 than could be shipped for export by rail or pipeline. This production affected storage levels, Canadian crude oil prices, and other market aspects. To protect the value of its oil, the Government of Alberta has temporarily limited production to match export capacity to prevent Canadian crude from selling at large discounts. Production curtailment requirements are to be assigned at the operator level and will be allotted by the provincial regulator to each operator.

Many First Nations in Alberta have expressed concern over Alberta’s oil production curtailment. Whereas oil and gas-producing provinces have access to other revenue streams – such as business and other taxes – to offset to some degree reductions in royalty revenue, not all oil and gas-producing First Nations have such additional revenue streams. Further, oil and gas royalty rates for production from First Nations lands are almost always higher than royalty rates in the surrounding province (royalty rates are generally higher for First Nations because the provinces receive revenue in other forms from the same business i.e., businesses pay royalty, fuel taxes, vehicle surcharges (registration), etc. to the provinces. Yet First Nations may only be collecting royalty and / or taxes, in the case of some First Nations. First Nation revenue stream from that one business is significantly lower than that of the province.). Since production curtailment requirements are assigned at the operator level, First Nations in Alberta are concerned that they will disproportionately be affected – that operators may decide to curtail their activities on First Nations lands, where they are paying a higher royalty rate, before they curtail their activities on other lands, where they are paying a lower royalty rate.

In response to the concerns raised by oil and gas-producing First Nations in Alberta, IOGC took the following actions:

1. A statement was prepared (IOGC Statement: Alberta Curtailment of Oil Production and the Price Differential) and was distributed in printed format at the 2019 IRC Annual General Meeting, sent by regular post to all oil and gas-producing First Nations in Alberta, and, posted on IOGC’s Internet website (Note: The IRC membership passed a resolution at that Annual General Meeting that called upon IOGC to engage the Province of Alberta on the oil production curtailment issue);
2. IOGC began regular, targeted monitoring of oil production from First Nations in Alberta to detect if First Nations were being disproportionately affected by the provincial initiative; and,
3. IOGC reached out formally to the Alberta Ministry of Energy to present First Nations’ concerns and to offer to meet face-to-face to explore mitigation measures. IOGC sent a letter to the Alberta Minister of Energy formally requesting that First Nations’ lands be exempted from an operator’s calculation of its oil production so that First Nations would not be negatively impacted by the curtailment. The Alberta Minister of Energy declined IOGC’s request yet offered to meet in-person with IOGC to further discuss the issue.

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 FY2018-2019, there were 18 BOCs holding 171 subsurface agreements comprising 59,440 hectares (25% of all lands managed by IOGC) of First Nations lands.

Oil Production from First Nations 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 FY2018-2019, oil was produced from 32 reserves belonging to 23 First Nations. The oil production history chart indicates that oil production from First Nations lands increased by about 15.4% compared to the previous year. Total First Nations oil production in FY2018-2019 was approximately 889,000 cubic metres, up from 770,000 cubic metres the year before. As in previous years, most of the oil produced from First Nations is heavy oil.

The majority of FY2018-2019 oil production, approximately 75.5%, came from First Nations in Saskatchewan, up slightly from the 2017-2018 percentage of 69.0%.

Description of figure A – History of Oil Production from First Nations lands, 2008-09 to 2018-19

This graph shows oil production from First Nation lands, in western Canada, from fiscal years 2009-2010 through 2018-2019. Units are in thousands of cubic metres per year:

• 2009-10: Alberta 443, Saskatchewan 275, Total 718;
• 2010-11: Alberta 552, Saskatchewan 459, Total 1,011;
• 2011-12: Alberta 665, Saskatchewan 517, Total 1,182;
• 2012-13: Alberta 658, Saskatchewan 445, BC 0.003, Manitoba 0.087, Total 1,103;
• 2013-14: Alberta 537, Saskatchewan 388, Manitoba 0.398, Total 925;
• 2014-15: Alberta 473, Saskatchewan 325, Total 798;
• 2015-16: Alberta 402, Saskatchewan 352, Total 754;
• 2016-17: Alberta 294, Saskatchewan 511, Total 805;
• 2017-18: Alberta 238, Saskatchewan 532, Total 770;
• 2018-19: Alberta 217, Saskatchewan 672, Total 889.

From fiscal year 2011-2012 to fiscal year 2015-2016, oil production from First Nations lands decreased from a peak of almost 1.2 million cubic metres to a low of 754 thousand cubic metres. However, oil production has since rebounded by almost 20% by fiscal year 2018-19, most of it from Saskatchewan First Nations.

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 oil prices, for example, are influenced principally by North American market conditions, proximity to their respective markets, pipeline and other infrastructure capacity and availability, alternate transportation options, the need for storage and blending or dilution, US drilling and production levels, and US crude oil inventories. Yet Canadian prices, like other benchmark and contract prices, also feel the effects of geo-political and geo-economic activities: OPEC; the Middle East; Russia; Mexico and Central America, to name just a few.

Fiscal year oil prices were robust until the realization of a sustained oil oversupply in December 2018 which, along with fears of a world-wide economic slowdown, led to a sudden falloff of prices. Most susceptible was the price of Western Canadian Select (i.e., heavy) oil. It fell disproportionately compared to other, lighter density, benchmark prices. Because the "average" First Nation oil is between heavy density and bitumen, that average price dropped, too. Once again, there was concern 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 Canadian Select (WCS), which exceeded $40 per barrel, much higher than the normal $10 to $12 per barrel differential and even higher than witnessed before, during the winter of 2018, when the differential was briefly in the $30 per barrel range (that time due to infrastructure constrictions and refineries that had been deactivated briefly).

January 2019, however, saw cooperation among Middle East Gulf states and Russia to reduce production and exports and prices were able to rebound, almost to the same levels that were enjoyed before the brief falloff. Please note that this international cooperation coincided with production cutbacks imposed by the Alberta provincial government at the time in Alberta. Some credit those cutbacks with having an effect on prices, but those cutbacks were merely coincidental to the much more significant international cutback cooperation.

As noted in previous annual reports, the usual reasons for the WTI-to-WCS price differential stem from the differences in proximity to market, oil density (called "specific gravity" or, simply, "gravity") and other characteristics, like sulphur content, acid content, and the presence of other contaminants, as well as infrastructure constrictions and routine pipeline, storage, and dilution costs. The price falloff in the autumn of 2018 was an extraordinary circumstance, but it still pointed at the vulnerability of Canadian oil prices, especially heavier oil prices.

Once again, oil and gas-producing companies, as well as oilfield service companies, are facing difficult financial circumstances. As reported last year, several had gone out of business, cut back on capital expenditures and other operations, been acquired by competitors, or left Canada. This past year, unfortunately, that has continued and, as long as commodity prices stay at low-to-mid levels, it is likely to get worse. Again, as stated 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, as stated above, 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, 2013-14 to 2018-19

This graph depicts the history of the prices of four types of Canadian crude oil through the five most recent fiscal years, 2014-15 through 2018-19.

In fiscal year 2014-2015, light density, sweet crude oil prices peaked near $700 per cubic metre during the summer of 2014 while prices for IOGC’s modeled and computed "average First Nation crude oil price" peaked in the mid-$500 range.

By January 2015, prices for light sweet crude oil had dropped to near $300 per cubic metre while the "average First Nation crude oil price" dropped to $200. Prices rallied briefly in summer 2015 to nearly $500 and nearly $400, respectively. Prices then declined until, by February 2016, they were at levels not seen since calendar year 2000.

Fiscal year 2016-17 brought a steady rise in oil prices. Light sweet crude oil prices were in the range of $350 to $400 per cubic metre while "average First Nation crude oil price" rose to a range between $260 to $280 per cubic metre.

Although oil prices fluctuated more during fiscal year 2017-2018 than fiscal year 2016-2017, they generally stayed within the same price range during both fiscal years.

In fiscal year 2018-2019, oil prices continued to rise. Light sweet crude oil prices reached just over $500 per cubic metre in summer 2018 while average First Nation oil prices reached the high-$300 range.

At the left hand side of Figure B, one can still see the end of the severe falloff in oil prices that began in the autumn of 2014. Those prices "bottomed-out" in the winter of 2015, then rallied to a certain extent into the summer of 2015, only to fall again even more severely. By the winter of 2016, prices were at their worst level in years.

The beginning of FY2016-17 saw the beginning of a slow – although fluctuating – climb in prices. There was a minor drop in prices over the summer of 2017, but they began a climb during late fall of 2017. That climb reached a sustained peak of $500 per cubic metre during the summer of 2018. As mentioned in the main body of this report, a US oversupply followed by pessimism over the world economy, led to a sharp drop in the autumn of 2018. But international cooperation among OPEC, Russia and others to bring about production and export cutbacks, resulted in another significant rally in prices, to nearly the same levels as the summer of 2018.

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 lands.

During FY2018-19, the IOGC-generated 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 followed the other oil benchmark prices – peaking near $400 per cubic metre in the summer of 2018, then falling significantly until it, too, rallied as a result of restoration of prices internationally in January 2019. At the end of FY2018-19, the average First Nation oil price hovered in the $300 to $400 per cubic metre range – again, just below the heavy oil-related Western Canadian Select prices. Meanwhile, that price, apparently, did not suffer as much as the other benchmarks during the autumn 2018 falloff, possibly due to contract prices or production circumstances.

Natural Gas Production from First Nations 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. However, no matter where the natural gas originates from, it needs to go through some sort of processing to become sales gas. This processing may be fairly simple or more complex.

During FY2018-2019, natural gas was produced from 47 reserves belonging to 34 First Nations. The natural gas sales history chart indicates that natural gas sales from First Nations lands decreased by only 0.1% from FY2017-18. Total First Nation gas sales was once again just above 1.8 billion cubic metres. The vast majority of First Nation interest sales gas still originates from Alberta First Nations at slightly over 98%.

Description of figure C – History of Natural Gas Sales from First Nations, 2008-09 to 2018-19

This graph shows Natural Gas sales (that is, processed sales gas; not to be confused with raw produced gas) from First Nations lands, in western Canada, from fiscal years 2009-2010 to 2018-2019. Units are in millions of cubic metres per year:

• 2009-10: Alberta 901, Saskatchewan 150, British Columbia 2, Total 1,053;
• 2010-11: Alberta 901, Saskatchewan 107, British Columbia 2, Total 1,010;
• 2011-12: Alberta 968, Saskatchewan 81, British Columbia 2, Total 1,051;
• 2012-13: Alberta 979, Saskatchewan 64, British Columbia 1, Total 1,044;
• 2013-14: Alberta 1,091, Saskatchewan 52, British Columbia 1, Total 1,144;
• 2014-15: Alberta 1,685, Saskatchewan 44, British Columbia 1, Total 1,730;
• 2015-16: Alberta 1,751, Saskatchewan 42, British Columbia 1, Total 1,794;
• 2016-17: Alberta 1,523, Saskatchewan 38, Total 1,561;
• 2017-18: Alberta 1,805, Saskatchewan 34, Total 1,839;
• 2018-19: Alberta 1,812, Saskatchewan 29, Total 1,841.

Natural Gas Prices

As stated in previous years, Canadian natural gas producers must compete for Canadian and US markets with US natural gas producers who have greater transportation infrastructure, less resistance to infrastructure expansion, higher commodity prices, and closer proximity to US and Canadian markets. Canada currently has no other market options, and won't have until LNG plants can be completed, allowing Canada to access new world markets.

As reported last year, FY2017-18 saw generally declining natural gas prices. FY2018-19 saw an initial continuance of that decline in prices until nearly historic "below $1 per gigajoule" lows were experienced in May and June of 2018. Thereafter, however, prices began to rally modestly until they reached a plateau of sorts in the autumn of 2018. Then, a couple of factors favoured them: the onset of the winter heating season with the realization that, due to cutbacks of natural gas drilling programs over the previous several years and the shutting in of gas fields to wait for "better times", natural gas storage capacity, used as a buffer in anticipation of winter, dropped to unprecedented low levels. The onset of winter increased demand for natural gas, therefore, causing a rapid increase in prices and those producers who could and did respond saw prices rise month-by-month to a peak of over $2 Canadian per gigajoule during a very cold February 2019. In March 2019, prices were still fairly steady near the $2 dollar level.

Again, we remind the reader that the somewhat higher natural gas prices quoted in the media every day do not reflect what Canadian producers get, they only reflect what American producers get because, among other factors, their fields are closer to their markets. Fields as far away as Canada must pay higher tariffs and fuel gas costs, for example, to supply those markets. Those costs affect the netback prices they receive.

Description of figure D – History of First Nation Weighted Average Sales Gas Prices versus Benchmark Prices, 2013-14 to 2018-19

The graph depicts the history of natural gas prices for the five most recent IOGC fiscal years, 2014-2015 through 2018-2019. Three prices are indicated:

1. Firstly, a history of prices for natural gas sold on the Alberta Spot market (that is, traded on a public exchange for immediate delivery);
2. Secondly, a history of Alberta Reference Prices, which are determined by the Alberta Government and then used to assess royalties owed to the province; and,
3. Thirdly, a history of IOGC’s modeled and computed weighted average prices received for sales gas produced from First Nations lands.

At the beginning of fiscal year 2014-2015, prices for natural gas were near a peak of over $4 per gigajoule yet had been declining since before 2014-2015.

This decline continued until prices reached a low at the beginning of fiscal year 2015-2016. Prices then began to rise slightly – with some fluctuation – until they reached a high of just under $3 per gigajoule in August 2015.

After that, prices generally decreased until May 2016 when they reached less than $1 per gigajoule – the lowest prices since 1995. Prices then began a slow, yet fluctuating, increase to approximately $3 per gigajoule in early winter (December 2016 to January 2017).

Prices fluctuated between $2 and $3 per gigajoule until May 2017 when they experienced another steep decline to below $1 per gigajoule in October 2017. Spot prices reached a low of 47 cents per gigajoule, their lowest price in decades.

The 2017-2018 winter heating season saw another price rally – to over $2 per gigajoule in November 2017 – followed by fluctuations around $2 through the winter.

Spring 2018 saw prices dropping to a level below $1 per GJ again while Spot and reference prices reached 78 cents per gigajoule in May 2018. Prices then began to rally modestly until they reached a short-term peak around $2 per gigajoule in February 2019. Prices then dropped to below $1 per GJ once more, where they finished fiscal year 2018-2019.

 

In Figure D above, natural gas prices for FY2014-15 are declining from a high in the previous FY2013-14. Prices generally declined until May 2016 when they began to rebound. They rose to a near-$3 per gigajoule peak in early winter (December) 2016. Prices fluctuated between $2 and $3 per gigajoule until May 2017, when they began another steep decline to sub-$1 per gigajoule in October 2017. The coming 2017-18 winter saw another price rally – to over $2 per gigajoule in November, followed by fluctuations around $2 through the winter. In the spring of 2018, they dropped to a level below $1 per GJ again.

Thereafter, however, natural gas prices began to rally modestly until they reached a plateau of sorts in the autumn of 2018. Then, a couple of factors favoured them: the onset of the winter heating season with the realization that, due to cutbacks of natural gas drilling programs over the previous several years and the shutting in of gas fields to wait for "better times", natural gas storage capacity, used as a buffer in anticipation of winter, dropped to unprecedented low levels. The onset of winter increased demand for natural gas, therefore, causing a rapid increase of prices and those producers who could and did respond saw prices rise month-by-month to a peak of over $2 Canadian per gigajoule during a very cold February 2019. In March 2019, prices were still fairly steady near that two dollar level.

Like crude oil, based on data received from companies producing natural gas on First Nations lands, IOGC also calculates a "weighted average First Nation natural gas price". Like the weighted average oil price, this gas price also provides an estimate of value and an indication of whether First Nation natural gas prices follow market prices.

During FY2018-19, the First Nation weighted average price for natural gas began at $1.37 per gigajoule, then declined to $0.94 per gigajoule in May 2018. It fluctuated for several months between $1 and $1.30 per gigajoule, then began to rise, echoing the benchmark spot price. It peaked just under $3 in the unexpectedly cold February 2019. In March, it was still near that level, at $2.61 per gigajoule.

When compared to the beginning of the fiscal year, the price had increased by just over 39%. Unfortunately, the price declined as it entered springtime and the beginning of FY2019-20.

4. Planning and Corporate Services Directorate

The Planning and Corporate Services (PCS) Directorate’s key responsibilities include management planning, administrative policy, human resources, finance, procurement, office administration, information management and information technology. PCS also acts as secretariat to the IOGC Co-Management Board. The PCS directorate includes five groups: Contracts and Administration; Finance; Human Resources; Planning, Administrative Policy & Corporate Coordination; and, Information Technology.

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.

Foster Collaborative Relationships That Support:

Industry

• 7.1 Clear and Consistent Service Delivery
• 7.2 Consistent Policy Application
• 7.3 Compliance

Government

• 8.1 Federal Alignment and Accountability
• 8.2 Federal – Provincial Collaboration
• 8.3 Other Government Initiatives

First Nations

• 9.1 Understanding
• 9.2 Administration of Lands and Resources
• 9.3 Collaboration & Information Sharing