Potential Asset Sale: Canadian Utilities Limited’s Generation Portfolio

On September 13, Canadian Utilities Limited (CU), a subsidiary of ATCO, announced that it would be exploring strategic alternatives for its Canadian electricity generation business. Canadian Utilities Limited is engaged in electricity (generation, distribution, and transmission), pipelines and liquids (natural gas transmission, distribution and infrastructure development), energy storage and industrial water solutions, and retail energy (electricity and natural gas retail sales). The company has 5,200 employees and assets of $21 billion.

CU owns and operates 2,391 MW across six Canadian jurisdictions, with the majority located in Alberta. The geographic composition of these generation assets and their fuel type are indicated in the pie charts below.  An overview of the individual generation assets is provided in the table below.

Power Advisory would welcome the opportunity to assist clients in understanding the opportunities presented by Canadian Utilities Limited’s announcement and other potential generation acquisitions across North America. 

A PDF version of this note is available here

John Dalton, President, Carson Robers Consultant, Robie Webster Jr., Researcher, Power Advisory


Review of Massachusetts Compromise Bill ‘An Act to Promote a Clean Energy Future’

On July 30, 2018, the conference committee appointed to reconcile the Senate and House clean energy bills finalized a compromise bill, H.4857. The bill’s contents more closely align with the House of Representatives bills passed last week (H. 4756 and H. 4739) than the omnibus Senate bill (S. 2545) (see Power Advisory’s report on the differences between the initially proposed bills). The House and Senate voted in favor of the bill on July 31, the last day of the legislative session.

Renewable Portfolio Standard

The compromise bill will increase the state’s Class I Renewable Portfolio Standard (RPS) at the rate proposed by H.4756. Between 2020 and the end of 2029, the rate would increase to 2% per year. After 2030, it would return to the current growth rate of 1%. The rate will ensure that the state procures 35% of Class I renewables (new resources) by 2030.

Offshore Wind

The bill directs the Department of Energy Resources (DOER) to conduct a cost benefit analysis for the procurement of an additional 1,600 MW of offshore wind by the end of 2035 and “may require said additional solicitations and procurements.”  This suggests that DOER doesn’t require additional legislative authority to mandate the distribution companies to solicit and procure this additional 1,600 MW of offshore wind.  The DOER can also require distribution companies to hold competitive procurements for offshore wind transmission to deliver energy from designated wind energy areas as long as it can serve more than one project. The transmission service cannot exceed 3,200 MW of total capacity. The procurement of offshore wind transmission must be the most cost-effective means to deliver offshore wind.

Interestingly, in the filing letter that it submitted to the Massachusetts Department of Public Utilities (DPU), DOER expressed strong support for the 800 MW Vineyard Wind Project and asserted that the “Project is highly cost-effective [and] significantly aligns with the Commonwealth’s goals of creating a clean, affordable, and resilient energy future for the Commonwealth.”  This clearly suggests that DOER has a favorable view of offshore increasing the likelihood of DOER mandating the procurement of an additional 1,600 MW of offshore wind.

Clean Peak Standard

The bill also provides for the creation of a Clean Peak Standard (CPS) for all retail electricity suppliers, which was detailed in H. 4756. The CPS will be in place starting January 1, 2019 and will require each retail electric supplier to meet a baseline percentage of sales with clean peak certificates. The clean peak certificate would be a credit received for each MWh of energy or energy reserves provided during a seasonal peak period. After 2019, every retail electricity supplier must provide a minimum of at least an additional 0.25% per year of sales met with clean peak certificates.  The legislation defines seasonal peak periods as the times when net electricity demand is the highest. The periods must be more than one hour but less than four hours in any season. A clean peak resource according could be any qualified RPS resource, an energy storage system, or a demand response resource that delivers energy to the distribution system during seasonal peak periods or can reduce load on the system. The DOER will need to establish the procurement mechanism of the certificates, the percentage of kilowatt-hour sales from clean peak resources, the seasonal peak periods, and an alternative compliance mechanism.

Energy Storage

Massachusetts’ current energy storage target is 200 MWh by 2020. The compromise bill increases this target to 1,000 MWh by December 31, 2025. Neither the House nor Senate bills included this specific target. Similar to H. 4739, the comprise bill will require electric distribution companies (EDCs) to file an annual distribution system resilience report that would highlight areas of the distribution system where non-wires alternatives could serve as system resiliency measures. EDCs can hold competitive solicitations for such non-wires alternatives. The legislation provided guidance on which monetary and non-monetary factors to be considered in a solicitation, which include: 1) resiliency improvements, 2) reduce greenhouse gas emissions, 3) reducing peak demand, 4) reducing congestion in constrained areas, and 5) benefits to low-income areas.

Power Advisory would welcome the opportunity to assist clients in understanding the opportunities created by these changes to the Commonwealth of Massachusetts’ clean energy policies.

A PDF version of the report is available here.


Review of Massachusetts House of Representatives Energy Bills Relative to the Senate’s ‘An Act to Promote a Clean Energy Future’

The Massachusetts House of Representatives passed two major energy bills on July 12, 2018. The bills address a subset of the legislation that was approved by the Massachusetts Senate omnibus clean energy bill (S. 2545) in June. The House bills are now in conference committee with the Senate and are expected to be reconciled ahead of the close of the legislative session on July 31.

Renewable Portfolio Standard

H.4756 would increase the state’s Renewable Portfolio Standard (RPS) to promote an accelerated procurement of renewable energy. Currently, the minimum percentage of Class I renewable energy that Massachusetts’ retail electricity suppliers must provide customers increases 1% per year through 2050. In the legislation, this rate would increase to 2% each year starting in 2021 through 2030. After 2030, it would return to the current growth rate of 1%. The increased rate would raise the RPS from the current target of 25% by 2030 to 35% by 2030. This goal is less aggressive than the Senate’s bill, which called for a 3% annual increase and an ultimate target of 100% renewable energy in the state by 2047.

Offshore Wind

H.4756 would also increase the state’s offshore wind procurement target to 3,200 MW by 2035, doubling the current procurement target of 1,600 MW by 2030. While this target is a significant increase to current levels, it is far less than the goal of 5,000 MW of OSW capacity by 2035 put forward by the Senate in S. 2545. With either target, Massachusetts is signaling that it is interested in making further commitments to the emerging US OSW industry. An increased procurement target will provide additional opportunities for the three existing wind energy lease holders and increase the value of the two remaining MA lease areas being auctioned by BOEM through ATLW-4A this fall.

Clean Peak Standard

H.4756 also includes a provision for the establishment of a Clean Peak Standard (CPS) for all retail electricity suppliers. Such a standard would ensure that Renewable Portfolio Standard (RPS) and greenhouse gas emissions reductions are met by having clean energy generation in peak load hours instead of fossil fuels. According to the bill text, the CPS could be similar to the state’s existing RPS, but the methodology would be established at a later date. If similar to the RPS, each retail electricity supplier would need to meet a certain percentage of their total sales with clean peak certificates, similar to renewable energy certificates (RECs) under the RPS. The clean peak certificate would be a credit received for each MWh of energy or energy reserves provided during a seasonal peak period. The legislation defines seasonal peak periods as the times when net electricity demand is the highest. The periods must be more than one hour but less than four hours in any season. A clean peak resource according to the legislation could be any resource that qualifies under the RPS, an energy storage system, or a demand response resource that delivers energy to the distribution system during seasonal peak periods.

Also, similar to the procurement of RECs, regulations could include a process through which clean peak certificates are competitively procured and electric distribution companies would enter into long-term contracts ultimately approved by the Department of Public Utilities. Seasonal peak periods would need to be established as well as an alternative compliance mechanism.

By the end of this year, the Department of Energy Resources (DOER) will determine the current kilowatt-hour sales from existing clean peak resources during seasonal peak load hours. This will be used to establish a baseline percentage of sales that must be met with clean peak certificates beginning on January 1, 2019. After 2019, every retail electricity supplier must provide a minimum of at least an additional 0.25% of sales that must be met with clean peak certificates. The procurement of clean peak certificates will not apply to municipal light plants.

The House’s bill is a response to Governor Baker’s legislation entitled “An Act Promoting Climate Change Adaptation, Environmental and Natural Resource Protection, and Investment in Recreational Assets and Opportunity.” This legislation called for a Clean Peak Standard. The Senate bill did not include language pertaining to a Clean Peak Standard.

Energy Storage

Massachusetts’ current energy storage target is 200 MWh by 2020. The Senate bill aimed to increase this target to 2,000 MW by 2025. While not increasing the energy storage procurement target, H. 4739 addresses the need for additional integration of storage into the transmission and distribution grids.

The bill would require electric distribution companies (EDC) to file an annual distribution system resilience report which will include maps that show the most congested areas of the distribution system as well as areas most vulnerable to power outages. These maps could serve as a basis for identifying areas that would require system upgrades that could be deferred or replaced by non-wires alternatives. Each EDC could then hold a competitive solicitation for now-wires alternatives (such as energy storage) from third-party developers that would serve a resiliency need of the grid. The Senate bill did not mention non-wires alternatives or a resilience report.

Greenhouse Gas Emissions

One topic that was not addressed in the House bills was greenhouse gas emission reductions. The Senate bill established additional interim GHG reductions goals of 35-45% below 1990 levels by 2030 and 55-65% below 1990 levels by 2040, beyond the existing goal of a 25% reduction by 2020. These new interim goals could help the Commonwealth stay on track to meet its economy-wide mandate for an 80% reduction in GHG emissions below 1990 levels by 2050 established in the Global Warming Solutions Act of 2008. Furthermore, S. 2545 directs that a market-based system to reduce emissions from the transportation sector be implemented by 2021, for the commercial and industrial building sectors by 2022, and for the residential building sector by 2023.

Power Advisory would welcome the opportunity to assist clients in understanding the opportunities created by potential changes to the Commonwealth of Massachusetts’ clean energy policies.

A PDF version of the report is available here.


Review of NYSERDA’s 2018 Renewable Energy Standard RFP

On April 25, New York Governor Andrew Cuomo announced the second Request for Proposals (RFP) for large renewable generation projects under the Renewable Energy Standard (RES), a component of the Clean Energy Standard (CES). The solicitation will be conducted by the New York State Energy Research and Development Authority (NYSERDA). The RFP is for approximately 1.5 million MWh of Tier 1 Renewable Energy Certificates (RECs) per year. The CES was adopted in 2016 and calls for 50% of the state’s electricity to be generated by renewable energy resources by 2030 (also known as the “50 by 30” goal).

A few new provisions were added in this solicitation that were not included in the first solicitation in 2017. NYSERDA will favor renewable energy projects that avoid overlap with prime agricultural land. In addition, the state is encouraging proposals that consist of renewable energy pairing with energy storage and supports Governor Cuomo’s commitment to deploy 1,500 MW of energy storage by 2025.[1] The RFP provides for an in-service date prior to November 30, 2022.

The RES is the state’s main way of achieving the CES goal. Under the RES, all Load Serving Entities in the state must procure new renewable resources (called Tier 1 resources) annually as increasing percentages of their total load. The compliance mechanism is the procurement of RECs. The RES requires NYSERDA to conduct regularly scheduled solicitations for the long-term procurement of RECs. These are called RES RFPs. The first of which took place in 2017, in which approximately 3,200,000 MWh of generation was procured. For this second solicitation, eligible technology types are: biogas, biomass, liquid biofuel, fuel cells, hydroelectric, tidal/ocean, solar, and wind. If the project’s first commercial operation date is on or after January 1, 2015, it is eligible for this solicitation. However, older projects may be eligible if they have undergone significant upgrades after 2015 or if an otherwise eligible unit is returned to service after 48 consecutive months of being out of commercial operation. Imports from control areas that are adjacent to the New York Independent System Operator (NYISO) can be eligible Tier 1 resources.

The solicitation process consists of three steps. Step One is the Resource Eligibility Determination in which NYSERDA confirms that the bid facility meets the Tier 1 resource general eligibility requirements. If the bid facility is deemed eligible, it then must submit Step Two – Application for Qualification. In Step Two, NYSERDA will evaluate the application package to ensure that the bid facility meets or exceeds a minimum threshold in each of five Minimum Threshold Qualification categories. These categories are: site control, interconnection, permitting, project development, and resource assessment. Bid facilities that meet the minimum Threshold Qualifications will move on to Step 3 – the Bid Proposal where proposals will be evaluated and scored based on: (1) the Bid Price, which will be weighted at 70% of the overall score, and (2) non-price factors.  The non-price factors will have a combined weight equaling 30% of the overall score allocated in terms of: (1) 10% Incremental Economic Benefits to New York State; (2) 10% Project Viability beyond the Minimum Thresholds; and (3) 10% Operational Flexibility and Peak Coincidence.

The solicitation timeline is outlined below:

Table 1: Solicitation TimetableSource: NYSERDA

Since this is a REC-only procurement, renewable project developers will have to manage energy price risks. The following figure illustrates the average levelized future prices per zone for 2019-2027:

Figure 1: NYISO Levelized Futures Prices from 2019-2027

Source: SNL, Power Advisory

As shown in Figure 1, the lowest energy prices can be expected in Zones E and D. Project developers will have to strategically determine the best location to site their project to receive higher energy prices.

[1] 10% of the points in the final stage of the evaluation will be allocated based on operational flexibility and peak coincidence.

A PDF version of this report is available here.


BOEM Atlantic Wind Lease Sale 4A (ATLW-4A) Proposed Sale Notice Published in the Federal Register

Earlier today, the Bureau of Ocean Energy Management (BOEM) released a Proposed Sale Notice (PSN) for the previously unleased commercial lease areas, OCS-A 0502 and OCS-A 0503, offshore Massachusetts. These lease areas represent the most immediate leasing opportunity for those who are interested in entering the Northeast offshore wind market, where states have already made commitments to procure almost 5,000 MW.

Today’s PSN outlines the proposed ATLW-4A sale, initiates a 60-day comment period, and will be followed by a public seminar (date to-be-announced, expected in the coming month). To participate in the lease sale your organization must be qualified as an eligible bidder by BOEM. All bidder qualification materials must be postmarked no later than the end of the public comment period – June 11, 2018.

Opportunities for Long-Term Contracts

 As established in the 2016 An Act to Promote Energy Diversity and under Section 83C, the Commonwealth of Massachusetts has a mandate to procure 1,600 MW of offshore wind by June 30, 2027. The state issued the first offshore wind RFP for 20-year Power Purchase Agreements in July 2017. The winner of Tranche 1, a project in the range of 200-800 MW, will be announced at the end of April or early May. The parties that acquire OCS-A 0502 and OCS-A 0503 are expected to be able to participate in subsequent tranches of Massachusetts’ OSW procurement.

Three factors,1) the capabilities of existing offshore transmission technologies, 2) relative proximity of these lease areas to other states, and 3) allowance of delivery to an adjacent control area that has been included in clean energy procurements to date, suggest that the opportunity for a long-term PPA extends beyond Massachusetts’ procurements to the rest of the Northeast and Mid-Atlantic. In fact, Connecticut has already sought proposals from the incumbent Massachusetts OSW area lease holders and NYSERDA has been clear in its intention for those lease holders to participate in their upcoming procurements.

Figure 1 below illustrates the existing and proposed federal lease areas and labels the known state procurement targets by 2030 (Massachusetts, New York, Connecticut, and New Jersey). Rhode Island has announced a goal of 1,000 MW of clean energy of which 400 MW are expected to be procured this year. Offshore wind is included in this goal, but there is not a clear procurement target in the style of Massachusetts 83C.

Figure 1: US Atlantic Offshore Wind Projects, Lease Areas, and Current Procurement Targets

       Source: BOEM, Power Advisory LLC

*National Grid has a transmission right-of-way for the operating Block Island Wind Farm. The inclusion of this ROW on the map does not indicate that National Grid is an OSW lease holder.

While a portion of these targets are anticipated to be committed before the ATLW-4A auction takes place and a winning bidder for OCS-A 0502 or OCS-A 0503 is in a position to submit a bid, opportunities for long-term contracts will remain under these targets. Furthermore, given the regional interest in OSW development, the region’s aggressive decarbonization goals, and anticipated cost reductions for OSW that are likely to allow it to compete directly with other clean energy resources additional opportunities for long-term contracts are anticipated.

Power Advisory would welcome the opportunity to help clients assess the opportunity presented by upcoming BOEM lease sales and to support North American offshore wind development activities.


Review of NYSERDA Renewable Energy Standard RFP 1 Results

On June 2, 2017 the New York State Energy Research and Development Authority (NYSERDA) issued the 2017 Renewable Energy Standard Request for Proposals (RESRFP17-1). The RFP was the first issued under the state’s Clean Energy Standard. The Clean Energy Standard requires that 50% of the state’s electricity come from renewable sources by 2030, representing about a doubling of the state’s renewable energy requirements. The standard puts an obligation on retail electricity suppliers to purchase increasing amounts of renewable energy to supply their customers. To assists these retailers in meeting their obligations, NYSERDA is required to support the development of large-scale renewable projects by issuing periodic requests for proposals (RFPs) to enter into long-term contracts (i.e., up to 20 years) with renewable energy developers. These RFPs provide for the purchase of renewable energy credits (RECs), rather than bundled energy and RECs.

The 2017 Renewable Energy Request for Proposals resulted in agreements to develop 26 new large-scale renewable projects. Of the 26 projects selected, 22 are solar, 3 are wind, and one is a hydroelectric project. In addition, one of the selected wind farms will include an energy storage component. The 26 projects will add 1,383 MW of capacity and generate 3.2 TWh per year, providing about 2% of the 50% 2030 target. The weighted average price for the Tier 1 RECs purchased was reported as $21.71. A map of the selected projects is included below:


Exelon’s Proposed Retirement of its Mystic Plant: Ensuring the Attention of ISO-New England

April 3, 2018

Last Thursday, Exelon Generation (Exelon) announced that it had filed with ISO-New England to retire the Mystic Generating Station’s Units 7, 8, 9, and the Jet unit on June 1, 2022.  Exelon noted “absent any regulatory reforms to properly value reliability and regional fuel security, these units will not participate in the Forward Capacity Auction scheduled for February 2019.”  Mystic offers over 2,000 MW of capacity, making it the largest generating station in Massachusetts and one of the largest in New England.   ISO-New England reported that Exelon submitted delisted bids in the Forward Capacity Auction that was conducted in February.

On March 17th at a New England Restructuring Roundtable Meeting, Gordon Van Weile, President & CEO of ISO-New England, opened the door to such regulatory reforms when discussing the fuel security analysis that the ISO had completed.  His presentation noted that the “The ISO can take action through its market design and tariff to procure ‘insurance’ to alleviate, but not eliminate, fuel-security risk.”  More specific references to possible changes were offered in his formal remarks.  In its Press Release announcing the proposed retirement, Exelon indicated that “ISO-NE recently stated that it may propose interim and long-term market rule changes to address system resiliency in light of significant reliability risks identified in ISO-NE’s January 2018 fuel security report.”

The significance of these retirements is exacerbated by the unique reliability attributes of these units.  First, they are located in the Northeast Massachusetts-Boston area, which has been found to be an import-constrained zone in the past and would likely be determined to be again with the retirement of this capacity.   Second while Mystic 8 and 9 are natural gas-fired, they are not connected to the interstate natural gas transmission pipeline network that serves New England. They are directly connected to the Everett LNG terminal.  Therefore, these two CCGTs are not subject to the same natural gas supply constraints that affect the rest of ISO-New England’s natural gas fleet.  This fact was recognized in ISO-NE’s fuel security analysis.

Interestingly, at this same time Exelon also disclosed that it would be purchasing the LNG terminal from ENGIE North America.  The ISO-New England fuel security analysis demonstrated the importance of the continued operation of the Everett LNG terminal to New England electricity supply reliability.  With a sustainable sendout of about .4 Bcf per day, after the volumes delivered to Mystic 8 and 9 are netted out, the Everett LNG terminal can provide about 9% of New England’s interstate delivery capability (excluding the output of the local LNG and propane storage facilities operated by the region’s gas distribution utilities.)

While one might question why Exelon would purchase the LNG terminal if it planned to retire two generating units that utilize about 30 to 40% of its throughput, with the purchase of the LNG terminal Exelon has purchased a natural gas fuel price hedge.[1] The purchase of the Everett LNG Terminal enables Exelon to secure the world-wide price for LNG for natural gas supplies for Mystic 8 and 9.  This will be beneficial during winter high demand periods, but could result in higher fuel prices in other periods unless Exelon is able to secure contracts with LNG suppliers that are based on an Algonquin City Gate (New England natural gas pricing point) netback price.  Conceivably, Exelon has elected to forgo the modest operating margins in many of these other hours to lock in greater margins during winter peak periods.[2]

Also contributing to the significance of the loss of this capacity is that Mystic 7 is dual-fueled (natural gas and residual oil) with a winter capacity rating of 560 MW.  The importance of dual-fuel capability to maintaining reliability was highlighted this winter, where in a two-week period New England oil-fired generation regularly represented upwards of 35% of the regional fuel mix.

ISO-NE will need to evaluate the reliability impacts of these proposed retirements, but cannot prevent the units from retiring.  This announcement would add to the growing list of retirements, which by the early 2020s would represent (with the addition of this 2,000 MW) about 23% New England’s generation capacity.

[1] The current price of natural gas for Mystic 8 and 9 is reported be pegged to the Algonquin City Gate price so that these units are generally ensured access to natural gas, but at a market price.

[2] Reported prices for LNG deliveries to the Everett Terminal in 2017 ranged from $3.03/MMBtu to $4.00/MMBtu from April to October 2017. US DOE, LNG Monthly, January 2018


Review of Possible Massachusetts Clean Peak Standard

Last week, Massachusetts Governor Baker submitted legislation to the Massachusetts Senate and House, “An Act Promoting Climate Change Adaptation, Environmental and Natural Resource Protection, and Investment in Recreational Assets and Opportunity”, as a key part of the administration’s Climate Change strategy.  The Legislation included $1.4 billion in capital authorizations for climate adaption and resilience.  Of particular relevance to New England’s electricity sector was a Clean Peak Standard that would require the Department of Energy Resources to establish a standard that requires “all retail electricity suppliers to provide a minimum percentage of kilowatt-hour sales to end-use customers in the commonwealth from clean peak energy resources.”

A Clean Peak Standard was first proposed by Arizona’s Residential Utility Consumer Office to ensure that a certain percentage of energy delivered to customers during peak load hours is delivered from clean energy resources.  Such a standard can help ensure that the environmental objectives of a renewable portfolio standard (RPS) are promoted and not frustrated by a significant reliance on fossil fuel generating resources during peak load hours.  RPS promote resources that provide the lowest cost energy, but with wind and solar providing the vast majority of such energy they can lead to an oversupply of energy in some periods (as reflected by negative market prices) and increases in the requirements for more flexible dispatchable resources in other periods.  This is illustrated by the Duck Curve, which reflects the significant increase in ramping capability that is required as result of the increased penetration of solar energy resources.  Figure 1 below shows California’s Duck Curve and the dramatic increase in the requirements for fast-responding resources, a significant proportion of which is likely to be natural gas-fired, from 4 to 7pm.

Figure 1: Net Load in California after Variable Resources: the “Duck Curve”

Source: CAISO (https://www.bloomberg.com/news/articles/2015-10-21/california-s-duck-curve-is-about-to-jolt-the-electricity-grid)

The Clean Peak Standard would require that a portion of qualifying electricity production be produced during the designated peak period to limit the need for natural gas-fired generating units that are commonly called upon to provide such a ramping capability.  Specifically, to qualify under the conditions reflected in Figure 1 generating resources would need to produce energy from 4 to 7pm and utilize a clean energy resource to produce this energy.  The filed legislation defines eligible resources as Class I renewable energy resources (which presumably would have to be dispatchable or schedulable), energy storage resources (which presumably would be charged with clean energy), or demand response resources.

With an objective to incent the development of new resources, rather than to increase the compensation realized by existing resources, there is likely to be a requirement that these be new resources.  This presents special challenges to demand response resources where it is more difficult to ensure that the resource is in fact incremental and not an existing resource seeking to secure higher revenues from a higher value market.  Similarly, energy storage resources presumably will need to demonstrate that the energy used for charging is “clean” and incremental.

The legislation calls for the Clean Peak Period to be when “electrical consumption results in a significant increase in greenhouse gas emissions, or an increase in electrical prices or transmission and distribution costs to end-use electricity customers” and be no more than 10% of the hours in the year.

Power Advisory would welcome the opportunity to assist clients in assessing opportunities created by the Clean Peak Standard regulation.

John Dalton, President, Power Advisory LLC

A PDF version of this report is available here.


Funding Opportunity: NRCan Emerging Renewable Power Program

On January 18, Canada’s Minister of Natural Resources, Jim Carr, announced the launch of an expression of interest for the Emerging Renewable Power Program (ERPP). The program was created to expand the portfolio of commercially viable renewable power technologies available in Canada, deploy demonstrated technologies at the utility scale, and achieve further electricity sector greenhouse gas emission reductions.

ERPP’s anticipated C$200 million in funding is part of the investment goal of C$21.9 billion that the federal government plans to roll out over the next 11 years under the Pan-Canadian Framework on Clean Growth and Climate Change. The collaborative plan was officially adopted in December 2016 by all provinces and territories, except for Saskatchewan and Manitoba, and targets a GHG emission level of 523 metric tons by 2030 (a 30% reduction from 2005 levels).


Source: Pan-Canadian Framework on Clean Growth and Climate Change, 2016

The funding opportunity is available to renewable power technology projects that satisfy the following eligibility requirements:

  • Meet the definition of an emerging renewable energy technology
  • Produce electricity for sale or use in Canada
  • Renewable power technologies established commercially, but have yet to be established in Canada; or
  • Renewable power technologies available in Canada, but have yet to be implemented on a utility scale
  • Minimum Capacity:
    • 4 MW for geothermal, offshore wind, tidal, and concentrated solar projects
    • 1 MW for emerging technologies, such as next-generation biomass, river current, other marine resources and new solar technologies
  • Help meet the commitments made under the Pan-Canadian Framework on Climate Change

Strategic environmental assessments for energy planning purposes may also be submitted to this program. Projects that are able to commission during the funding period of April 1, 2018 to March 31, 2023 will be given priority. A per project funding limit of $50 million for up to 50% of eligible project expenditures is established in the Expression of Interest. However, greater than $50 million may be available with approval from the Treasury Board, such as for offshore wind which is likely to require more than the limit due to project size.

Expression of Interest (Due Feb. 11, 2018)

An expression of interest is now open but is not a prerequisite to participate in the forthcoming Request for Proposals. NRCan plans to use the expressions of interest to more accurately determine the level of funding that will be made available and the number of projects that can be expected to be funded.

Interested parties can receive the application package by submitting an email with company name, project name, and contact information. For your convenience we have made a copy of the EOI Applicant Guide and form on our website. The application requests details regarding applicant entity, general project information, and costs. The expression of interest application should be returned in Excel format along with a PDF of the signatory page by February 11, 2018, 11:59 pm EST.

Request for Proposals (Due Q3/Q4 2018)

Following the closure of the EOI process, the program will launch a Request for Proposals. Applicants will have approximately two months to complete the proposal template, which will be made available in the coming months. Our expectation is that the RFP could be released as soon as Q2 or Q3 2018.

Power Advisory would welcome the opportunity to support responses to the Emerging Renewable Power Program and to assess opportunities for emerging power technologies across North America’s electricity markets.

John Dalton, President, Carson Robers, Consultant and Caitlin Laber, Researcher, Power Advisory LLC

A PDF version of this report is available here.


Summary and Commentary on Ontario Energy Board’s Strategic Blueprint: Keeping Pace with an Evolving Energy Sector

On December 18, 2017, the Ontario Energy Board (OEB) released its Strategic Blueprint (“Blueprint”), a guide for the OEB’s work over the next five years.  The Blueprint outlines four challenges that the OEB expects to encounter as the electricity sector transforms through 2022 and goals to address those challenges.  The challenges presented by the OEB are: transformation & consumer value; innovation & consumer choice; consumer confidence; and regulation “fit for purpose.” (see figure below)

Each challenge is customer-centric, which aligns with the OEB’s consumer focus in their day-to-day operations.  This memorandum provides a short summary of the Blueprint along with our commentary.

To support their claim that the sector is undergoing major transformations, the OEB highlights their observations of current trends and how those trends relate to their role as a regulator.  The following is a summary of the trends.

  • The sector is experiencing fast-paced technological innovation with distributed energy and storage resources creating opportunities for customer generation and micro grids.  These advances may challenge the traditional role of utilities could lead them to change their business models to accommodate customers or groups of customers generating their own electricity.
  • Innovation surrounding new renewable technologies has been driven by the need to reduce carbon emissions and mitigate the effects of climate change.  As Ontario focuses on greenhouse gas emission (GHG) reductions through the new cap-and-trade system, obligations will affect natural gas distributors that the OEB regulates.  The shift from fossil fuels to renewable energy will impact all electricity distributors that the OEB regulates.  The potential for extreme weather events will results in a growing focus on system resiliency as well.
  • The OEB notes that the structure of the electricity sector has changed, and will continue to change due to mergers and acquisitions of Local Distribution Companies (LDCs) along with alternative business structures such as alliances and associations of LDCs to share services.
  • The 2016 Independent Electricity System Operator’s (IESO’s) Ontario Planning Outlook emphasized that current regulatory frameworks may have to change to keep up with rapid innovations in the electricity sector.
  • As customers are able to take advantage of new technologies such as use energy storage or distributed generation, focusing on customer expectations is critical.
  • In 2012, the Renewed Regulatory Framework was introduced and was expected to drive stronger customer engagement by utilities and a focus on long-term value for customers.  However, the OEB has not seen utilities focus on long-term value for customers to the extent that was expected.  Therefore, the OEB will assess the need for new approaches to consider innovative, low-cost solutions (e.g., traditional capital investments versus non-capital investments).

The OEB concluded that with the changes underway in the sector, a reactive regulatory approach to challenges that arise will not work in Ontario.  However, they do not see a need to mandate a sweeping new business model for utilities to be prepared for the rapid change occurring in the sector (e.g., to better incorporate renewable technologies) because it may impede innovation.  Instead, the OEB plans to prepare utilities and customers for changes in the sector and alleviate negative consequences from such changes through support and guidance.

The Blueprint provides details on the four challenges that the OEB will face in the coming years, the goal for each challenge, and how the OEB will achieve each goal. Each challenge is outlined below.

Transformation & Consumer Value

The OEB aims to strengthen utilities’ focus on delivering value to customers as the sector evolves.  Network and infrastructure investments may be necessary to support micro grids and renewable technologies as demand for such technologies increases.  The OEB plans to remunerate utilities in ways that will incentivize their focus on long-term value solutions for customers.  The OEB will also support regional planning and associations of utilities to share resources.  New requirements for utilities to reflect sector changes in their system planning and operations may be implemented in the next few years.

Innovation & Customer Choice

The OEB intends to support LDCs as they embrace innovation in their operations.  To achieve this, the OEB will look to reimburse utilities in ways that will encourage them to pursue technological innovations in their operations and services.  Modernizing the OEB’s rules and codes and addressing regulatory barriers to innovation will also be important steps to implement new technologies for consumers.  Under the Regulated Price Plan, the OEB will continue to provide consumers greater choice in the way they pay for electricity.

Consumer Confidence

The OEB’s goal for this challenge is to ensure that customers understand their rights and have confidence that regulators will protect their interests.  One important way the OEB plans to achieve this is to continue to include customer participation in decision-making processes and proceedings, especially those related to rate changes.  The OEB also plans to modernize utility customer service rules and to work with LDCs on customer pilots for new services and pricing models.

Regulation “Fit for Purpose”

The OEB states that they have the resources and expertise needed to address the changing electricity sector.  The success of their customer-centric strategy will depend on ensuring access to expertise, providing staff with opportunities to understand sector changes, continuing to engage with LDCs, and continuing to serve as an expert advisor to the government on energy policy issues.

The Blueprint affirms that for the OEB, customer interests are key and LDCs will be compensated for keeping that interest central to their operations.  As reducing GHG emissions becomes the driving factor for a shift toward renewable technologies, LDCs will be expected to keep pace while simultaneously providing low cost solutions.

OEB Strategic Goals and Objectives: 2017 to 2022

Power Advisory Commentary

Power Advisory generally agrees with the trends identified by the OEB in their Blueprint.  In particular, the rapidly falling costs of distributed energy resources (DER) (e.g., solar, energy storage, etc.) offers consumers an option to manage part or all of their electricity needs outside of the traditional LDC framework.  The OEB in recent consultations (i.e., EB-2015-0043 Rate Design for Commercial and Industrial Electricity Customers: Aligning the Interests of Customers and Distributors) has stated the objective of “ensuring value of connection to the Ontario electricity system”.  In short, this means that LDCs and the OEB must strive to ensure that the cost for consumers to remain connect to the Ontario electricity system is greater value than the cost of going disconnecting (‘off-grid’).  Therefore, the challenge for the OEB and LDCs is to determine how existing electricity infrastructure remains a safe and reliable delivery model for consumer’s electricity needs while supporting greater consumer choice in alternative delivery methods.  One option would be to increase the utilization of the existing electricity infrastructure through new control methods and leveraging the beneficial attributes of DERs (e.g., the flexibility of energy storage facilities to reduce constraints during peak demand hours).

The release of the Blueprint is consistent with the Ontario Government’s 2017 Long-Term Energy Plan, which emphasized the need to adapt to technology innovations and provide greater value and choice to customers.  The Blueprint is also anticipated to be a key input with respect to the newly established expert panel considering the modernization of the OEB, which was announced December 14, 2018 by the Minister of Energy.  Power Advisory continues monitor these initiatives and is available to provide additional support to clients on these matters as required.

A PDF version of this report is available here.