Canadian Energy Law : Lawyers & Attorneys for Environmental Energy Law

This legislative silence has caused uncertainty as to ownership of coalbed methane on freehold lands where mineral title is split between the coal owner and the natural gas rights holder, and where the instruments at issue do not refer expressly to coalbed methane. In some instances, this has resulted in litigation between the coal owner and the natural gas rights holder, with both parties claiming ownership of coalbed methane.

The history of coalbed methane ownership in Alberta originates in late 1800s, when the Crown granted 25 million acres of surface and mineral land to Canadian Pacific Railway (“CPR”). The CPR subsequently sold this land to settlers, but reserved to itself an interest in “all coal”, “all coal and petroleum” or “all coal, petroleum and valuable stone”. Since natural gas was not reserved it was sold with the lands. This has resulted in the split title situation that exists today, where freehold landowners hold natural gas rights and the CPR’s successors and assigns hold the rights to coal.

Because the initial grants and subsequent instruments did not until recently speak to coalbed methane, Bill 26 aims to clarify ownership of coalbed methane in split title situations. By declaring coalbed methane to be and at all times to have been natural gas, Bill 26 provides certainty as to the inclusion of coalbed methane in initial natural gas grants.

Coalbed methane is a natural gas found in coal. Coal seams with coalbed methane potential are found underneath much of Alberta, especially in southern and central Alberta. Notably, a study by the Alberta Geological Survey found that Alberta’s coalbed resource may contain approximately 500 trillion cubic feet (Tcf) of coalbed methane. In contrast, the estimated ultimate potential of marketable conventional natural gas in Alberta is between 205-253 Tcf.

The Bill will come into force on Royal Assent. Depending on the amount of questioning from opposition, this could take anywhere from two weeks to several months.
 

Existing agreements entered into by the natural gas mineral owner, or their lessee, that specifically granted coalbed methane rights to the coal owner, or their lessee, will not be affected. The Bill also protects the Crown, coal owners, or their lessee, and surface owners from being sued by the natural gas owner, or their lessee, for coalbed methane extraction, production or removal prior to the Bill coming into force.

Coal seams with coalbed methane potential are found underneath much of Alberta. Notably, a study by the Alberta Geological Survey found that Alberta’s coalbed resource may contain approximately 500 trillion cubic feet (Tcf) of coalbed methane. In contrast, the estimated ultimate potential of marketable conventional natural gas in Alberta is between 205-253 Tcf.

To take effect, the Bill must receive Royal Assent. Depending on the amount of questioning from opposition, this could take anywhere from a week to several months.

Royalty adjustments

The Competitiveness Framework identifies two areas of concern with the current, and only recently implemented (January, 2009), royalty regime that are making Alberta a less attractive oil and gas investment destination:

1. FRONT-END RATES
   
   The Competitiveness Framework found that Alberta's front-end royalty rates on natural gas and conventional oil are significantly higher than those found in other jurisdictions competing for energy investment and creates too much front-end risk.
    
2. MAXIMUM ROYALTY RATES
   
   The Competitiveness Framework also found that Alberta's maximum royalty rates are too high in comparison to its peers. For example, at a price of $120.00 per barrel, Alberta's maximum royalty rate on conventional oil is 49%, whereas British Columbia's is 18% and Saskatchewan's is 19%.
   
   As a result of these competitive royalty concerns and also with a view to encouraging innovation and technology development in the sector, the Government of Alberta has announced it will take the following actions:
   
   
   • The current royalty framework for natural gas and conventional oil will be modified effective January 1, 2011;
      
   • New royalty curves will be reviewed and any changes announced prior to May 31, 2010;
      
   • The current temporary incentive maximum 5% front-end rate on natural gas and conventional oil will become permanent effective January 1, 2011;
      
   • The maximum royalty rate for conventional oil will be reduced from 50% to 40% effective January 1, 2011;
      
   • The maximum royalty rate for natural gas will be reduced from 50% to 36% effective January 1, 2011; and
      
   • The transitional royalty framework introduced in November 2008 for certain deep wells will continue until December 31, 2013, provided that as of January 1, 2011, no new wells will be allowed to select the transitional rates.

Regulatory process improvements

The Review identified a lack of coordination among the various government agencies involved in the regulation of the oil and gas industry, which has resulted in a cumbersome and duplicative system, requiring unnecessary effort by industry participants and causing unnecessary delays. The Review determined that in order to regain competitive ground, Alberta's regulatory system needs to be more efficient and practical.

To address the need to reduce red tape in this area, the Government of Alberta proposes in the Competitiveness Framework to take a number of actions, including the following, over the next six months:

• coordinated compliance programs are to be in place by October 2010;
   
• Alberta Environment will streamline its process for pre-disturbance assessments; and
   
• the Energy Resource Conservation Board will streamline processes for well spacing in certain categories and for in-situ oil-sands-development approval amendments.

In addition, the Government will form a task force to undertake a review, involving industry and stakeholders, of its regulatory system for resource development to ensure alignment with an "outcome-based approach." The task force is to issue a report within ninety days regarding (i) short-term enhancements that can be made to the system to facilitate the development of new technology, as well as (ii) the process it will undertake for its comprehensive review of the regulatory system.

Industry reaction

While some industry players have expressed concern as to whether the Government of Alberta has adequately addressed changes needed to make deeper wells economic or to spur shale gas activity in the Province, the industry reaction has been generally favorable. In particular, the Canadian Association of Petroleum Producers views the new policy reflected in the Competitiveness Framework as a positive change to the existing royalty structure. The Small Explorers and Producers Association of Canada also reacted positively to the effect the changes reflected in the Competiveness Framework would have on small producers. As the Government's action plans are implemented over the next few months, and in particular the new royalty curves are announced, the impact of the changes reflected in the Competitiveness Framework will be better understood.

1. development of seven regional land-use plans based on new integrated planning regions that are congruent with Alberta's major watersheds;
    
2. creation of a Land-Use Secretariat to support the implementation of the LUF and creation of Regional Advisory Councils (RACs) for each land-use region;
    
3. use of cumulative effects management on a regional basis to manage the impacts of development on land, water and air;
    
4. development of policy instruments to encourage stewardship and conservation of public goods;
    
5. promotion of efficient use of land;
    
6. establishment of an information and monitoring system to ensure that the outcomes of the LUF are being met; and
    
7. inclusion of Aboriginal peoples in land-use planning.

Regional plans

The Alberta Government is developing, with input from the public, stakeholders and Aboriginal communities and advice from the RACs, seven regional land-use plans covering all of Alberta. The regional plans will be the key documents in terms of future planning for each of the seven regions. When the regional plans are made effective, all decisions involving land-use (including all project development decisions) must be consistent with the provincial policies and directions set out in the regional plans. The ALSA provides that the regional plans will be binding on all persons in Alberta, including the Crown, municipal governments and decision-making boards. While regional plans will be enforced, for the most part, by existing mechanisms, the regional plans may contain penalty and enforcement provisions in order to ensure compliance with their terms.

The Government of Alberta has indicated that regional plans will contain a regional profile, the policy context for the plan, a regional vision statement, objectives and goals, strategies, actions and approaches, and monitoring and reporting. Regional plans are intended to paint a picture of how a region should look over several decades as well as desired outcomes for the region, with a planning horizon of up to 50 years. Regional plans will be designed to be effective for a five to 10 year period, after which they will be reviewed and updated as needed to address the realities of the day.

The newly established Land Use Secretariat is charged with leading the development of the regional plans, monitoring and reporting on the planning process for the plans and will also be involved in the development of all regulations associated with the plans under the ALSA.

Conservation tools

The ALSA also provides for a number of conservation and stewardship tools:

• Conservation Easements - easements that can be registered on title and voluntarily granted by a registered landowner to qualified organizations in order to protect land for some environmental or agricultural purpose.
   
• Conservation Directives - may be implemented by Cabinet in regional plans for the purpose of protecting some environmental or natural aspect of land. Upon doing so, Cabinet is required to provide the registered landowner with notice of the conservation directive and the landowner can seek compensation from the Government of Alberta.
   
• Stewardship Units - an environmental offset market for stewardship units may be implemented, which could involve marketable, bankable credits representing an environmentally positive action.
   
• Conservation Offset Programs - regulations under the ALSA may be implemented that would require project developers to counterbalance the environmental impacts of their activities by taking environmentally protective steps (such as purchasing stewardship units or arranging for the establishment of conservation easements on other lands).
   
• Transfer Development Credit Schemes - may be implemented in order to direct development away from ecological areas.

The impact of the ALSA

To support and ensure compliance with the regional plans, consequential amendments were made to more than 25 pieces of legislation as a result of the ALSA. Examples of amended provincial legislation that may be of particular interest to industry include the Municipal Government Act, the Public Lands Act, the Energy Resources and Conservation Act, the Mines and Minerals Act and the Water Act.

The regional plans may expressly affect, amend or extinguish statutory consents or the terms or conditions of any statutory consent. Statutory consents under the ALSA include permits, licenses, registrations, approvals, authorizations, dispositions, certificates, allocations, agreements or instruments issued under or authorized by an enactment or regulatory instrument. To the extent that a regional plan under the ALSA affects any holders of statutory consents, those holders will be given reasonable notice and an opportunity to propose alternate means of achieving or maintaining the goals or objectives of the regional plan without altering the statutory consent in question.

Next steps

The Alberta government intends to have all seven regional plans completed by the end of 2012. At present, RACs have been established for the South Saskatchewan and the Lower Athabasca regions and have begun the process of developing their recommendations regarding those regional plans, including public consultations. The Government intends to have those regional plans developed by 2010. The Lower Athabasca region includes the Athabasca and Cold Lake oil sands areas, while the South Saskatchewan region includes Calgary and much of southern Alberta. The Government has also released Terms of Reference for the Lower Athabasca Region, in which the Government has provided the Lower Athabasca RAC with some policy guidance in terms of its recommendations for that region.

The Land Use Secretariat has begun work on applicable regulations for the ALSA, including a regulation which will govern the public consultation process for development of the regional plans.

Given the significant potential impacts of regional plans, industry stakeholders may wish to become involved in the consultation processes for the regional plans in their regions and the regulatory framework in relation to those plans.
 

In April 2008, in response to an overwhelmingly negative reaction from the oil and gas industry, the government introduced two new royalty programs designed to encourage the continued development of deep, high-cost oil and gas reserves, to be implemented concurrently with the New Framework. In November 2008, Alberta introduced an incentive program making companies drilling new natural gas or conventional oil wells from 1,000 to 3,500 metres in depth, eligible for a one-time option to select new transitional royalty rates. These rates remain applicable between November 19, 2008 and December 31, 2013, and companies to which the transitional rates apply will be required to shift to the New Framework on January 1, 2014. The Alberta government estimated that offering the transitional rates would result in a potential reduction of projected royalties of approximately $172 million in 2009, rising to $512 million in 2013, depending on such factors as the number of new wells paying transitional royalty rates, actual production rates and commodity prices.

However, as predicted, despite such efforts to soften the blow to the oil and gas industry, the implementation of the New Framework appears to have been a significant factor in lower levels of investment (and resulting lower production) in the Alberta oil and gas industry during 2009. In response, the Alberta government announced another incentive program in March 2009, providing a new, one-year, $200-per-metre drilled royalty credit for new conventional oil and natural gas wells, and a maximum five percent royalty rate for the first year of production from new oil or gas wells. Additionally, the province will invest $30 million in a fund committed to abandoning and reclaiming old well sites and to encouraging the clean-up of inactive oil and gas wells. On June 25, 2009, the government extended the March 2009 energy incentive program by one year, to March 2011, to attempt to alleviate the significant downturn in the oil and gas industry by encouraging investment. 

Since the New Framework was announced, the Alberta government has introduced a variety of new programs that have increased the complexity of the regime-precisely what the New Framework was supposedly designed to avoid. It remains to be seen whether these new programs will attract much-needed investment into the Alberta oil and gas industry. What seems clear is that the Alberta Government has realized its misjudgement of the Alberta royalty regime and is now taking the steps it deems necessary to try to rectify the problem.

The AUC approved the FBR plan for a five-year term and allowed for an additional two years, given that at the time of the AUC's decision, two years had already elapsed. The AUC recognized that the longer the term, the stronger the incentives for efficiency improvements. Under the circumstances, the AUC found that the approved term, from January 1, 2007 to December 31, 2013, would provide significant efficiency incentives and benefit both EPC and its customers. The AUC noted that the longer term would also reduce the regulatory burden for EPC, its customers and the AUC.

The FBR plan also contains various mechanisms intended to protect ratepayers. One of these is an earnings-sharing mechanism, whereby earnings over and above a certain threshold are to be shared equally between EPC and its ratepayers by way of a reduction in future rates. The approved earnings-sharing mechanism is "asymmetrical" in that customers share in earnings above the target return on equity, but have no corresponding risk if EPC's earnings are below target.

Quality-of-service performance standards are also part of the FBR plan. If EPC fails to meet its proposed performance standards, it will be faced with up to $2,000,000 in financial penalties.

The FBR plan also includes re-openers and off-ramps that allow for the occurrence of extrinsic events beyond the control of EPC and that protect against the impact those events may have on EPC. Changes or re-openers to the FBR plan must be approved by the AUC.

The FBR plan is intended to provide EPC with incentives that more closely mimic the incentives found in the competitive market is expected to result in benefits for both EPC and its customers that could not be achieved under the traditional cost-of-service approach to ratemaking.
 

Deep oil wells
One of the new programs is designed to provide certain royalty adjustments for deep oil wells. Exploration wells over 2,000 metres will be subject to royalty adjustments to offset higher drilling costs and provide a greater incentive for producers to continue to pursue new, deeper oil plays. Such deep oil wells will qualify for up to $1 million or 12 months of royalty offsets, whichever comes first. This program is a five year program to begin on January 1, 2009, and will only be applicable to wells drilled after April 10, 2008. According to Alberta Energy, wells deeper than 2,000 metres represent 20% of all oil wells drilled in Alberta and 26% of new conventional oil production between the years 2002 and 2007.

Deep natural gas wells
The other new program is designed to encourage continued deep gas exploration and will replace the existing Royalty Adjustment Program. This program applies to wells deeper than 2,500 metres and will provide for a sliding scale of royalty credits according the depth of the well, up to $3,750 per meter. As with the new deep oil program, the deep natural gas program is a five year program to begin on January 1, 2009, and will only be applicable to wells drilled after April 10, 2008.  Alberta Energy reports that wells over 2,500 metres represent 5% of natural gas wells drilled in Alberta and 27% of natural gas production from the years 2002 to 2007.

Framework amendments
As a result of its "unintended consequences" analysis, the Government has announced that the Framework will be clarified such that four par prices will be used to calculate royalties on oil, rather than two par prices, allowing royalties to be calculated based on a price closer to that received by the producer. Par price calculations are a weighted average market price of a wide range of crude types. Currently two par price calculations are used, one for heavy oil (greater than 25.7º API gravity) and one for non-heavy oil (less than 25.7º API gravity). The new par price calculations (light par, medium par, heavy par and ultra-heavy par) will yield royalty rates that better represent the economics of the specific oil play in question.

The Framework has been further clarified to reflect that natural gas royalties will be calculated based on the sum of vertical drill depths and all laterals, with the intent of encouraging greater development of coal-bed methane and reducing the environmental footprint of oil and gas exploration and production projects in Alberta. This is perceived as good news for horizontal drillers as natural gas royalties will be calculated on combining both vertical and lateral drilling.

Future royalty programs
Mel Knight, Alberta's Energy Minister, confirms that the Government still intends to follow through with earlier commitments in the Framework and introduce a shallow rights reversion program (estimated to be announced in the fall of 2008), as well as a bitumen-in-kind program, allowing oilsands producers to pay royalties on bitumen in kind. The Government remains optimistic that they will reach the goal of implementing all new programs by January 1, 2009.

Alberta was the first province to take action against GHG emissions; introducing a legislative regime in the spring of 2007. Under the regime, facilities with yearly GHG emissions over 100,000 tonnes are obliged to make annual emissions intensity reductions. The regime provided the foundation for Canada's first mandatory carbon trading market, commencing July 1, 2007. The Alberta government is still developing the rules of this market and hopes to have a system in place later this spring. In the interim, trading for compliance is already occurring. An offset system, including certain approved protocols and a registry, is already up and running in the Province. Offsets are considered to be a key compliance option for regulated entities under the Alberta regime.

In addition, CCS is receiving significant attention in Alberta as in other provinces and at the federal level. A number of large industrial emitters in Canada perceive significant opportunities for CCS in Western Canada and, through an alliance called ICO2N, have expressed a willingness to invest in CCS and use the Western Canadian Sedimentary Basin's estimated capacity to store emissions. Given its potential capacity to generate emissions credits (and its potential assistance in petroleum recovery), CCS may prove to be of significant importance in the development of emissions trading, both in Alberta and federally.

Royalty review report

The Panel released its report, entitled "Our Fair Share - Report of the Alberta Royalty Review Panel", on September 18, 2007 (the Report). The Report's general conclusion was that Albertans do not receive their fair share from energy development and that the existing royalty system, which differentiates between conventional oil, natural gas (including coalbed methane) and oil sands, should be modified.

The following summarizes the discussion contained within, and conclusions expressed in, the Report:

Conventional oil and natural gas

Royalty rates for conventional oil and for natural gas currently depend on a number of factors, including when the oil or natural gas pool was discovered. Generally, royalty rates for newly discovered pools are lower than royalty rates for older pools. The amount of royalties is calculated on each individual well and is based on the quantity of oil or natural gas produced from the well, the vintage of the pool that the well produces from, the market price of the oil or natural gas and the cost of processing the Government's royalty share of the applicable commodity. Above certain market prices, the royalty rates remain constant.

Under the existing royalty system, natural gas royalty rates start at 15% of production and increase as market prices increase to a maximum of 30% of production for newer pools and 35% of production for older pools after the market price reaches $3.60 per gigajoule. Adjustments for low producing wells can reduce royalty rates to 5%. Royalties for natural gas byproducts are related to the market price of those byproducts and can range from 15% to 50%. For conventional oil, the average royalty rate in 2005 was about 15%, with lower royalty rates applying to many wells in the Province. The maximum royalty rate is dependent on the vintage of the oil pool.

The Panel has recommended a simplified royalty system for conventional oil and for natural gas. Among the recommendations of the Panel are the following:

• the tiers of royalties based on year of discovery of the pool should be eliminated; 
   
• the caps on royalty rates for natural gas and conventional oil should be raised to $17.50/MMBtu and $120/barrel, respectively; 
   
• the price-sensitive royalty rate and the quantity-sensitive royalty rate should become separate elements within a single formula with the maximum total royalty payable being 50% of production; 
   
• producers within "Township 53", an area classified many years ago as "oil sands" for administrative purposes, should no longer be able to elect to have their conventional oil wells administered under the oil sands royalty regime; 
   
• the royalty formula for conventional oil should apply to propane, butanes and pentanes plus; and 
   
• all incentive programs, including the incentives to drill deep gas wells, should be eliminated.

Collectively, the Panel's recommendations provide for an increase in the total Government take from conventional oil revenues from 44% to 49% and an increase in the total Government take from natural gas revenues from 58% to 63%. The total Government take includes royalties and all applicable provincial and federal taxes.

Oil sands

The current royalty system for oil sands production is a generic system established in 1997 to encourage investment and development of the oil sands. A royalty rate of 1% of the project's gross revenue currently applies for the period up to payout - when the developer has made profit equal to the capital invested in the project plus an allowance equal to the long term government bond interest rate, to recognize financing costs during the construction period. The royalty rate after payout is currently the greater of:

• 25% of the project's net revenue (gross revenue minus allowable costs), and 
   
• 1% of the project's gross revenue.

While the royalty rate is a flat rate, the rate is price sensitive as it adjusts with profits which are correlated with oil prices.

The Panel concluded that the base royalty rate of 1% for the pre-payout period is still appropriate; however, the net royalty rate after payout should be increased to 33% from 25% and the base royalty rate should be payable in addition to the net royalty rate after payout.

One of the most significant changes recommended by the Panel is the introduction of an Oil Sands Severance Tax (OSST). The OSST would be a tax levied against gross revenues from bitumen production. The OSST rate would be linked to the price of West Texas Intermediate (WTI) crude oil in Canadian dollars with the rate being zero for WTI prices of less than $40/barrel, growing by 0.1% for each $1/barrel increase thereafter and reaching a maximum of 9% at $120/barrel. The Panel recommended that the OSST payments should not be considered allowable costs for purposes of calculating the net royalty payable after payout or for calculating net income for corporate income tax purposes.

Several other recommendations were put forth by the Panel relating to the classification of oil sands projects, the elimination of the provincial component of the accelerated capital cost allowance provided for in the federal Income Tax Act, the introduction of upgrader royalty credits and the evolution of a bitumen pricing methodology.
Collectively, the Panel's recommendations would provide for an increase in the total government take from oil sands revenues to 64% from 47%.

Additional general recommendations of the Panel that are noteworthy are the recommendation against grandfathering and the establishment of an accountability program. Consequently, if adopted, all recommendations would apply equally to all participants at the same time. As well, the Panel suggested the government implement a means to both assess the effectiveness of the revenue policy on an ongoing basis and to collect royalties associated with energy resources in Alberta.

Government response

The Premier of Alberta addressed the Province on October 25, 2007 and released the "New Royalty Framework" at that time (the Framework). The Framework outlines the details of Alberta's new royalty regime and sets out the following three guiding principles in the government's decision-making process:

• to support sustainable economic development that contributes to a high quality of life for all Albertans now and into the future, 
   
• to support a fair, predictable and transparent royalty regime, and 
   
• to align Alberta's royalty system with overall Government objectives.

The following summarizes the changes to the existing royalty system set out in the Framework:

Conventional oil and natural gas

The Government decided to adopt the recommendations of the Panel for conventional oil royalties, subject to a few modifications. Royalties are to be set by a single sliding rate formula and will be calculated on monthly production, as is currently the practice. Royalty rates will range from 0% to 50% depending on the market price of oil with a rate cap of $120/barrel. In addition, as recommended by the Panel, the Government will eliminate the system of tiers that distinguished vintages based on the discovery date of the oil pool and will eliminate several special oil-related royalty programs.

The Government has recommended similar changes to the existing royalty system for natural gas. Royalty rates for natural gas will now range from 5% to 50% depending on the market price of natural gas with a rate cap of $16.59 per gigajoule.  The Government will also eliminate the tiers that distinguished vintages based on the discovery date of the gas pool.

Of particular significance is the Framework's departure from the Panel's recommendation to eliminate all incentive programs relating to the production of conventional natural gas. The Government will retain the Otherwise Flared Solution Gas Royalty Waiver Program and will extend this program to bitumen wells. In addition, the Government has agreed to revamp the Deep Gas Drilling Program rather than eliminate it. Support for this program is thought to be crucial for the viability of deep gas drilling projects in the Province. There is still some uncertainty about the intended changes to this deep gas incentive program and we hope that the Government will provide further details in the near future.

The Government will establish facility effective royalty rates to calculate the Government's share of capital for gas processing facilities. This is expected to improve the link of capital costs for natural gas to a particular facility within the Province.

Further, royalty rates for natural gas liquids will be modified and set at 40% for pentanes, and 30% for butane and propane. The royalty rate for ethane will not change and it will continue to be treated as natural gas.

Oil sands

The Government decided not to accept the Panel's recommendation to charge an OSST. The Government feels the proposed OSST is a tax to meet revenue needs whereas the royalty system is based on ownership rights. Instead, the Government will introduce a price sensitive base royalty rate for oil sands production. Under the new system, the base rate (pre-payout) will start at 1% and will increase for every dollar that oil is priced above $55/barrel, to a maximum of 9% when oil hits $120/barrel. The net royalty payable post payout will start at 25% and will increase for every dollar oil is priced above $55/barrel, to a maximum of 40% when oil hits $120/barrel. It is unclear whether the Government intends to keep the existing post-payout mechanism whereby the producer pays the greater of the base rate based on gross revenues and the net royalty rate based on net revenues.

The Panel's recommendation to implement a 5% upgrader royalty credit was rejected. The Government has decided to look at other methods of encouraging value-added activity in the Province, including taking its royalty share in kind to supply potential upgraders and refineries in Alberta.

In addition to the above system, the Government will eliminate its part of the accelerated capital cost allowance for oil sands projects. As well, "Township 53" projects will continue to have the choice of being subject to the oil sands royalty regime. Finally, the Government has committed to the implementation of a generic bitumen valuation methodology by June 30, 2008 to be used to value non-arm's length transactions.

Other changes

The Panel's recommendation for further accountability has led to the initiation of a review to improve the systems and structures used to collect, verify and report royalty revenues received by the Province. This review is to be completed by March 31, 2008.

Collectively, the changes to Alberta's royalty regime are estimated to increase royalty revenue by $1.4 billion in 2010, which amounts to a 20% increase in revenues forecast for that year under the current regime.

Implementation

The new royalty regime will take effect in January 2009. Significant changes will need to be made to numerous pieces of legislation including the Mines and Minerals Act, the Petroleum Royalty Regulation, the Oil Sands Royalty Regulation and the Natural Gas Royalty Regulation. The Government agreed with the Panel's recommendation not to grandfather existing oil sands projects. The Government is currently in discussions with Syncrude and Suncor, whose agreements expire in 2016, to participate in the new oil sands royalty system. The legal, economic and political implications of opening up these agreements for renegotiation will have to be considered by the Government and other interested parties.

Industry response

The response from the oil and gas industry to the Panel's Report was overwhelming and universally negative. Among the complaints were that the Panel's conclusions were premised on unrealistically low capital cost estimates, particularly for oil sands development and deep gas drilling projects. Large industry participants had stated there will be severe declines in exploration and development expenditures in the Province if the recommendations of the Panel were fully adopted, thus weakening the Alberta economy and offsetting the increase in royalty revenues for the Province that the Panel estimated will be generated through the implementation of the recommendations in total.

The response from the oil and gas industry to the Framework are muted compared to the response to the Panel's Report, but it still appears to be negative. Most large industry participants have yet to fully comment on the Framework. However, it is anticipated that there will be a decrease in the level of drilling activity in Alberta in the upcoming drilling season as a consequence of the Framework as industry participants work through the impact of the Framework to gain a better understanding of the increased costs to them.

Conclusion

The Premier's stated goal was to meet the objectives of the Report. Although the Panel's recommendations were not adopted in full, there is no doubt the Framework will have a significant impact on the economy in Alberta and Alberta's share of future oil and gas royalties. The extent of this impact has yet to be determined.

The History of the Case

The case concerned the allocation of proceeds from the sale of buildings and land owned by ATCO in downtown Calgary that were no longer required for the provision of utility services. ATCO is a privately owned natural gas distributor in Alberta that is regulated by the Board and was required to get Board approval for the sale. The contentious part of the application was ATCO's proposal to distribute the net proceeds from the sale to its shareholders. The City of Calgary, representing the interests of ATCO's customers, opposed ATCO's proposed distribution and argued that ratepayers were entitled to a portion of any net gain on the sale.

After concluding that ATCO's customers would not be harmed by the disposition and approving the sale, the Board utilized its general authority to "impose any additional conditions that the Board considers necessary in the public interest" to re-allocate a portion of the net sale proceeds to ATCO's ratepaying customers. The Board determined it was necessary to balance the interests of both shareholders and ratepayers within the "regulatory compact" - under which a utility is granted a statutory monopoly in exchange for limitations on its rate of return and freedom to deal with property included in its rate base - and allocated one-third of the net gain to ATCO and two-thirds to the benefit of ratepayers. In the Board's view, it was not in the public interest to award the entire gain to the utility, as this might encourage speculation in non-depreciable property or motivate the utility to dispose of properties for reasons other than the best interest of the regulated business.

ATCO appealed the decision to the Alberta Court of Appeal on the grounds the Board lacked the jurisdiction to re-allocate the net sale proceeds and that the decision was unreasonable. The Court of Appeal agreed the Board had exceeded its jurisdiction and referred the matter back. The City subsequently obtained leave to appeal the decision to the Supreme Court.

In a 4-to-3 split decision, a majority of the Supreme Court determined the Board did not have the prerogative to revise the distribution of proceeds from the sale of a utility's discarded assets. The majority's decision was written by Justice Michel Bastarache, who held the applicable provisions were silent as to the Board's power to deal with sale proceeds and that the power could not be implied from the statutory regime as necessarily incidental to the Board's explicit powers. The decision of the three dissenting justices was authored by Justice Ian Binnie, who concluded that the public interest was a matter of opinion and discretion best left to the expertise of the Board.

As stated above, the decision has important implications for the interaction of regulatory powers with the private property rights of a utility and the scope of a regulator's condition-making power. Each of these implications will be examined in turn below.

The Balancing of Regulatory Power and Property Rights

In the majority decision, Justice Bastarache examined the relationship between the broad powers of a regulator and the property rights of utility owners, and took the opportunity to resolve a longstanding point of contention by ruling that the "regulatory compact" does not cancel the private nature of the utility or allow ratepayers to implicitly acquire ownership or control of the utility's assets by paying rates.

In reaching this conclusion, Justice Bastarache noted the Board had broad powers to supervise the finances of utilities and their operations, but held this authority was in practice incidental to fixing rates to ensure that all customers have access to the utility's services at a fair price. Although utilities have a "public interest" aspect, the capital invested is not provided by the public purse or customers, but is "injected into the business by private parties who expect as large a return on the capital invested in the enterprise as they would receive if they were investing in other securities possessing equal features of attractiveness, stability and certainty" and this will "necessarily include any gain or loss that is made if the company divests itself of some of its assets." He concluded the Board had misdirected itself by confusing the customers' interest in obtaining safe and efficient utility service with an interest in the underlying assets owned only by the utility.

Interestingly, Justice Bastarache dismissed the suggestion made by the Board that allowing a utility to retain the entire gain would encourage speculation in non-depreciable property. To the contrary, he was of the opinion that speculation would accrue even more often if the utility's shareholders were not the ones to benefit from the possibility of a profit because investors would expect to receive a larger premium for their funds through the only means left available - the return on their original investment - and would be less willing to accept any risk.

Justice Binnie took a decidedly different approach to this issue in his dissenting decision. At the outset, Justice Binnie rejected ATCO's characterization of the case as one of property rights. In sharp contrast to the majority's reasoning, Justice Binnie noted, "ATCO chose to make its investment in a regulated industry" and "the return on investment in the regulated gas industry is fixed by the Board, not the free market."

Although he also rejected the City's argument that ratepayers acquire title to a utility's physical assets, Justice Binnie broke from the majority by accepting what he called the "risk" theory. Under this approach, the allocation a portion of the net gain from an asset sale to ratepayers could be justified in some, but not necessarily all, circumstances because the ratepayers had guaranteed the utility "in bad times and good, a just and equitable return on its investment in this land and these buildings." He reinforced this argument later in the decision by pointing out that "ATCO's contention that it alone is burdened with the risk on land that declines in value overlooks the fact that in a falling market, the utility continues to be entitled to a rate of return on its original investment even if the market value at the time is substantially less than its original investment."

Looking forward, the majority's robust statement on the importance of maintaining private property rights and the entitlement to a fair return brings certainty to the contentious issue of whether ratepayers gain proprietary interest in a utility's assets. That the minority also agreed on this point will provide clarity for future regulatory proceedings. What is less clear is how the majority's rejection of Justice Binnie's "risk" theory will fare in actual practice. In light of the guarantee of a fair return under the regulatory compact, it is questionable whether utilities will risk a loss on an asset sale in a poor market where the option to continue employing that asset in a utility service and receiving a fair rate of return is available. The test of time will also determine whether the majority's reasoning as to why allocating the entire gain to shareholders will lessen, as opposed to increase, speculation proves to be accurate.

Limits of a Regulator's Condition-Making Power

The ATCO decision is also important because it provides guidance on the limits of a regulator's power to impose conditions in the public interest. On behalf of the majority, Justice Bastarache acknowledged the concept of "public interest" is very wide and elastic, but stated this does not mean unfettered discretion and a regulator's power "will necessarily be limited to only what is rationally related to the purpose of the regulatory framework".

With respect to this particular case, Justice Bastarache determined the Board's authority was grounded in its main functions of rate-setting and protecting the integrity and dependability of the supply system, and there was no evidence that it needed the power to re-allocate proceeds to accomplish its objectives. In his view, it was not necessary for the Board to have control over which party should benefit from the sale proceeds to fulfill those functions and such a power was not related to the purposes of the power to approve the sale, which he identified as: (i) preventing degradation in service quality; (ii) maximizing the aggregate economic benefits of utility operations; and (iii) preventing favouritism toward investors.

Justice Bastarache expressed the concern that allowing the Board to re-allocate proceeds in the absence of an express legislative authority would allow broadly drawn powers to be interpreted in a manner that could encroach on the economic freedom of the utility, which would be contrary to the well-established rule of interpreting potentially confiscatory legislative provisions cautiously. Nevertheless, Justice Bastarache was careful to make it clear that the decision did not mean the Board could never attach a condition to the approval of an asset sale. As examples, Justice Bastarache noted the Board could approve an asset sale subject to an undertaking to replace the assets and their profitability or to invest part of the sale proceeds in maintaining "a modern operating system" that achieves the optimal growth of the system.

By contrast, Justice Binnie rejected ATCO's contention that the case was about the Board's confiscatory power. In his view, the essential issue of the case was whether the courts were justified in limiting what the Board was allowed to consider necessary in the public interest. In that regard, he acknowledged that the Board's discretion is not unlimited and must be exercised in good faith for its intended purpose; however, as the public interest is largely and inherently a matter of opinion and discretion, the Court should not substitute its own view for that of the Board. Key to this determination was Justice Binnie's review of regulatory practice in Alberta and elsewhere, which demonstrated that a variety of approaches have been adopted by regulators in solving the problems confronting the Board. He noted that it would have been open to the Board to allow ATCO's application for the entire profit, but that the Board's decision was within the range of established regulatory opinion and did not call for judicial intervention.

The ATCO decision is notable because of the narrow approach the majority adopted toward the scope of a regulator's condition-making powers. The Court's approach is particularly striking in this case because the Board's enabling statute granted the regulator considerable discretion in imposing such conditions as it considered necessary in the public interest. The majority's narrow reading of the Board's condition-making power seems at odds with the recent judicial trend (reflected in the minority opinion) to defer to the expertise of regulatory bodies with respect to their exercise of discretion.

The practical outcome of the decision is that regulators will now be required to examine whether the use of their condition-making power is consistent with both the regulator's broader objectives and the purposes of the underlying request for approval. That said, the majority's framework for determining when a regulator can employ its condition-making power leaves considerable room for regulators and lower courts to distinguish future cases. Regulators and lower courts are likely to face some difficulty in future cases when determining whether a specific exercise of condition-making power is more analogous to the conditions imposed by the Board in this specific case or to the acceptable alternatives suggested by Justice Bastarache. Also, given the persuasive strength of Justice Binnie's dissenting opinion, it is difficult to know if the majority's limitation of a regulator's condition-making power will have an appreciable effect on the actions of regulators beyond the ATCO case.