Canadian Energy Law : Lawyers & Attorneys for Environmental Energy Law

The Report contains the following six recommendations to improve the distribution sector:

1. LDC Consolidation: The 73 currently existing Local Distribution Companies (LDCs) should be consolidated into 8 to 12 large regional distributors (RDs).
    
2. No sale of Hydro One assets: In order to give effect to LDC consolidation, Hydro One should be directed to lead and engage in merger talks with the appropriate utilities with a view to create new RDs with contiguous boundaries. There should be no “across-the-board” sale of Hydro One assets.
    
3. Transition Advisor: The Ontario government should appoint a Transition Advisor to oversee LDC consolidation.
    
4. Transition cost recovery: LDCs’ that voluntarily submit a new license application to the Ontario Energy Board (OEB) within a proposed merger period should recover their reasonable transaction costs, including third-party facilitation cots.  
    
5. Cost Savings: Any cost savings realized by the consolidation should be re-invested into the newly formed RDs in order to strengthen the distribution system post-consolidation.
    
6. Governance: The membership of Boards of RDs should have at least 2/3rds independent directors. Also, current prohibitions on municipal governments making loans to LDCs should be removed. Finally, affiliates currently owned by LDCs should not be included in any consolidation.

Stay tuned to this blog for further analysis of the Report and its recommendations.

Although the submissions to the Panel have been provided on a confidential basis, a few stakeholders have published their submissions on their respective websites, including but not limited to, the Ontario Chamber of Commerce, the Society of Energy Professionals, the Electricity Distributors Association, the Consumer Council of Canada, the Association of Municipalities of Ontario and the Ontario Energy Association. As can be expected, the views on the matter range from complete support for the consolidation of LDCs to a full opposition of a mandated consolidation plan. One particular group, the Society of Energy Professionals (the Society), even proposes a unique idea to consolidate the industry. The Society suggests creating one entity, which they call the “Ontario Electricity Delivery Company” (the OEDC), that would combine the transmission and distribution assets of Hydro One with those of all the other LDCs in the province, regardless of their current ownership, into one entity. In return for transferring assets to the OEDC, current Hydro One and LDC owners would receive equity in the consolidated company in proportion to their contribution.

The Panel has been given 12 months to review all of the submissions and report back to the Minister with any recommendations. As of right now, a list of submitters is not publicly available and there is no mention of whether the final report will include a submission list. The entire energy industry is following the matter quite closely and will be very interested to read the final report.

The report can be read here: http://www.energy.gov.ab.ca/Electricity/pdfs/CTRCPoweringOurEconomy.pdf 

FIT Review

The Drummond report advocates for the reduction or elimination of various energy subsidies, most notably the Ontario Clean Energy Benefit, and takes aim at the above-market-level rates that have been offered through the feed-in tariff (FIT) program for renewable energy generators. 

Drummond recommends lowering the initial prices offered in the FIT contract and introducing degression rates that reduce the tariff over time. He cites the example of Germany’s equivalent tariff program that builds in an annual nine per cent rate reduction. Beyond mitigating the impact on electricity prices, the purpose is to encourage innovation and discourage reliance on public subsidies.

Energy Procurement

The report suggests procuring larger generation facilities through a request for proposal (RFP) process, and making wholesale electricity prices inclusive of transmission costs as part of a comprehensive restructuring of the wholesale electricity market. Drummond also raises the possibility of locational marginal pricing when he suggests that consumers located nearer to generation stations should have the benefit of lower electricity prices.

OPG and Hydro One

Drummond suggests the province consider the full or partial sale of OPG and Hydro One if net, long-term benefits can be clearly demonstrated through comprehensive analysis. As well, he tells government to stay out of rate setting, a practice that often leads to greater costs down the road. Drummond’s report also recommends public-private partnerships for these government enterprises as a means of promoting efficiency in order to service and retire the debt and liabilities of the old Ontario Hydro as soon as possible.

LDCs

Drummond singled out the inefficiency of Ontario’s 80 LDCs as an area for improvement. His report recommends consolidating LDCs along regional lines to create economies of scale and potentially save $1.35 billion now spent on operations, maintenance and administrative costs.
 

Starting November 1, 2011 these facilities will be required to submit both site-specific data in addition to their own forecasts. Once the IESO has implemented its central forecasting approach, renewable generators will no longer be required to submit their own forecasts. However, there is no indication from the IESO of an exact date centralized forecasting will be implemented.          

Of particular note, the market rule amendment specifies reporting standards. 

In addition to dynamic data, both wind and solar facilities will be required to provide information concerning the physical layout and details of the facility (“static data”) at the time of connection assessment and/or registration. A summary of these collection requirements are found below.

Wind  

For wind facilities, the following static and dynamic data will be required:

Additionally, the IESO had mandated collection standards for dynamic data listed above. At minimum, each facility will be required to provide this data from nacelle mounted data collection points. Every turbine is required to be within 5km from the nearest data collection point. Furthermore, each facility over 10MW will be required to provide data from at least one standalone meteorological tower. The number of towers required will correspond to the facility size (MW). Towers will be required located on the prevailing upstream side of the wind facility in areas that have representative microclimates and winds at hub height. Data is to be reported to the IESO in real-time every 30 seconds.

Solar

For solar facilities, the following static and dynamic data will be required:

Like wind, solar will be subject to data collection standards. At minimum, each facility will be required to have two meteorological data collection points. All solar arrays in that facility are required to be within 12km of a collection point. Data must be provided to the IESO every 30 seconds.

For both wind and solar PV, there is no requirement that the data collection devices be owned by the same owner of the facility.

Stakeholder Engagement

These new obligations are part of a larger IESO plan to accommodate the phase-out of coal and increased contribution of wind and solar. These developments will significantly impact Ontario’s electric grid. Declining demand and variability associated with renewable sources could result in a surplus of baseload generation. Furthermore, the IESO is facing a reduced flexibility to deal with the variability of supply due to increased regulatory constraints and limited ramping ability of gas facilities (compared to coal).

In an attempt to accommodate this variability, the IESO will implement changes to three major areas: forecasting, visibility and dispatch. The IESO is currently undertaking stakeholder engagement initiative (SE-91) in an effort to include stakeholders, such as developers and distributers, in the talks surrounding these changes.

Currently, eleven design principles have been approved relating to the three areas of change. This amendment is based upon SE-91 Renewable Integration Final Design Principles - Principles 1, 4 and 5. 

The Ontario Power Authority (OPA) is watching SE-91 closely. It has committed to working with supplies on OPA contract issues that may result from these IESO rule amendments (RESOP, RESIⅈ RESIII, FIT, HCI).

In any event, the IESO will continue consulting with stakeholders in renewable integration. Currently, two working groups for SE-91 exist: the Dispatch Technical Working Group and the Visibility Technical Working Group. This fall, the IESO intends to form a dispatch merit order working group that will comment on the order of curtailment in the event of baseload surplus.

For more information on SE-91 or to participate in the next meeting, email stakeholder.engagement@ieso.ca.

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.
 

Subsection 86(2) requires leave before any person may acquire shares of an electricity distributor that, together with any shares already held by that person, will in the aggregate exceed 20% of the shares of the distributor. Essex argued that the provision only applied to transactions that put the purchaser "over the threshold" of a 20% shareholding.  Board staff opposed the application and asserted that leave was required for any transaction that resulted in a person holding more than 20% of a distributor's shares, regardless of that person's shareholdings prior to the transaction.

The Board's three member panel split on the proper interpretation of subsection 86(2). The two-member majority, consisting of Vice-Chair Gordon Kaiser and Ken Quesnelle, sided with Board staff and adopted what they referred to as the "Major Shareholder" interpretation.  In their view, requiring leave for all transactions that result in a person holding more than 20% of a distributor's shares is consistent with the plain wording of subsection 86(2) as well as the legislative intent and history of the provision.   Drawing on the history of utility regulation in Ontario and the United States, the majority concluded that such transactions must be reviewed because they may expose the utility to greater financial risk (thereby increasing the cost of borrowing and leading to higher rates) or impose covenants that might impact a utility's operations. The two members determined that these concerns do not end when a shareholder crosses the initial 20% threshold and noted that further increases in person's shareholdings "only heightens concern" because those "with greater shareholdings are more likely to have the ability to control the financial structure of the utility."

The dissenting member, Paul Vlahos, criticized the majority's reasoning, stating that "[a] desire or inclination to exercise some form of regulatory oversight is not a proper guide in my view to the Board's consideration of its own jurisdiction." In his opinion, subsection 86(2) was properly interpreted to be consistent with the definition of "control person" in the Securities Act and only require a review at the 20% threshold.  He rejected the argument that subsection 86(2) provided for continued oversight of a distributor's major shareholders, noting that a review under subsection 86(2) is at best sporadic and, once a shareholder has effective control of a distributor, it can impose restrictive covenants at any time. Rather, Mr. Vlahos' opined that the appropriate way to protect ratepayers from harm is through the Board's broad ratemaking authority, which is not fettered by restrictive covenants, shareholder directives or any other shareholder agreements.

The framework for this initiative was set out in the Energy Conservation Leadership Act, 2006, which came into force earlier this year. The legislation allows for the creation of a "Smart Metering Entity" with the power to administer and deliver any part of the initiative and to engage in competitive procurement activities. Although details of the Smart Metering Entity have not been finalized, it appears that this entity will be responsible for procuring and operating the equipment necessary for the collection and management of data from the smart meters, while local distributors will provide actual meters. The government has yet to create or designate an agency as the Smart Metering Entity.

Responsibility for the initial stages of the smart metering initiative has been handed to the Independent Electricity System Operator (IESO). The Ministry of Energy has proposed a draft regulation that adds to the IESO's role the responsibility to "plan, manage and implement" and "oversee, administer and deliver" the smart metering initiative, or any aspect of the initiative. To fulfill these objectives, the draft regulation proposes that the IESO would have the authority to implement a schedule and plan for the initiative, to manage and develop the functional requirements for smart meters and the collection of data, and to prepare and manage competitive procurement processes for the services and systems necessary to operate smart meters. It is not clear whether the provincial government has any plans to eventually designate the IESO as the Smart Metering Entity.

On August 29, 2006, a regulation containing the principles that will govern the procurement of smart metering equipment by distributors came into effect. The regulation identifies authorized discretionary metering activities that can be undertaken by a distributor, notwithstanding the prohibition on such activities contained in the Electricity Act, 1998. The regulation also obligates distributors to ensure that the procurement process for smart meters meets specified criteria, including:

• the procedures used in the process and the selection criteria must be fair, open and accessible to a range of interested bidders;

• the procurement process must be competitive;

• bidders must disclose and implement measures to address any actual or potential conflicts of interest; and

• there must be no unfair advantage in the procurement process.

Regulations concerning the technical specifications and cost recovery for smart meters and the associated technologies also came into effect on August 29, 2006. For residential and small general-service consumers, the prescribed criteria are specified in the Ministry's publication entitled "Functional Specification for Advanced Metering Infrastructure," dated July 14, 2006. While ultimately subject to approval by the Ontario Energy Board, the regulations allow a distributor to recover costs that relate to the functionality of the smart meters and the associated technologies that meet the minimum criteria specified in the Ministry's publication. If a distributor's equipment exceeds the Ministry's minimum criteria, the distributor must convince the Board that the excess functionality will benefit the distributor's customers in order to recover any additional costs.