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.


Potential Portfolio Sale: Review of NextEra Energy Canadian Assets

On January 26th, NextEra Energy executives announced that the company is considering the sale of its Canadian assets. John Ketchum, Executive Vice President of Finance and Chief Financial Officer for NextEra Energy, stated during an Q4 and full-year 2017 earnings call that the company is exploring the sale of its Canadian portfolio to recycle capital back into its U.S. assets, which are expected to benefit from recent corporate tax reform. NextEra is continuing to evaluate this opportunity and will provide updates regarding this potential sale in the coming months.

Operating in four provinces, NextEra Energy’s Canadian assets include two solar projects (40 MW) and nine wind projects (675 MW). All but one of these projects have long-term contracts with the respective purchasing entities in each province.

Figure 1: NextEra Energy Canadian Project Locations

NextEra Energy Canadian Portfolio – Solar

NextEra Energy Canadian Portfolio – Wind

It is unclear to what extent there is a tax advantage for NextEra to go ahead with the sale and when it might occur. Interested parties would benefit from taking a detailed look at each of the potentially available assets to evaluate their fit with their existing generation portfolio. In particular, the 7 solar and wind projects located in Ontario may be attractive given the number of years remaining in their contract terms. Any participant in Alberta and Ontario’s wholesale markets must consider the implications of the ongoing market design and evolution processes in these jurisdictions to assess the implications on future revenue opportunities.

With offices in Toronto and Calgary Power Advisory follows Canadian electricity markets closely and would welcome the opportunity to help clients assess this potential project acquisition opportunity and to evaluate other generation assets across North America.

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

A PDF version of this report is available here.


Federal Lease Opportunity: BOEM Atlantic Wind Lease Sale 4A (ATLW-4A)

A competitive leasing process has been initiated by the Bureau of Ocean Energy Management (BOEM) for the previously unleased Massachusetts commercial lease areas, OCS-A 0502 and OCS-A 0503, in response to two unsolicited lease requests by Statoil Wind US LLC (December 16, 2016) and PNE Wind USA, Inc. (January 4, 2017). This lease sale follows the first offshore wind lease area auction for Massachusetts in 2014/15 (ATLW-4) and will be identified as Atlantic Wind Lease Sale 4A (ATLW-4A) in the Federal Register (These lease areas (0502 and 0503) are shown along with the existing lease areas and the parties that hold them in the figure below). The target is to hold the competitive auction near the end of September 2018 (See Figure 2 below).

Figure 1: Rhode Island and Massachusetts OSW Lease Areas

Given the policy support for offshore wind in Massachusetts, Connecticut and New York it is expected that the upcoming lease sale will be highly competitive. In ATLW-4 only Offshore MW LLC and RES Developments Inc. offered bids – the auction lasted two rounds and resulted in prices of $1-2 per acre. Bay State Wind (Ørsted and Eversource Energy) acquired OCS-A 0500 from RES and Offshore MW is now Vineyard Wind (Avangrid Renewables and Copenhagen Infrastructure Partners). For those who are not incumbent lease holders but interested in entering the Northeast offshore wind market and participating in procurements such as subsequent tranches of the Massachusetts 83C solicitation, this is the most immediate opportunity.  Additional lease areas offshore New York will also be made available, as new potential Wind Energy Areas (WEAs) are under consideration as of late 2017.

Figure 2: Indicative ATLW-4A Timeline

The timing of the competitive leasing process was estimated by Power Advisory based on the average of the previous seven OSW lease sales, BOEM’s regulations, and professional opinion. See our October report on the Massachusetts offshore wind lease opportunity for more information on the auction format and points to consider when evaluating participation.

John Dalton, President and Carson Robers, Consultant, Power Advisory LLC

A PDF copy of the report is available here.

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 ISO-NE Operational Fuel Security Analysis

Earlier this month ISO-New England (ISO-NE) released a report (Operational Fuel-Security Analysis) detailing the findings of a fuel-security analysis that was initiated to assess concerns with the region’s increasing reliance on natural gas-fired electricity. This dependence is set to increase with the retirement of oil, coal, and nuclear power plants. Increased reliance on natural gas, with limited incremental development of the region’s natural gas pipeline capacity is projected to increase fuel security risks for New England.

The report identified fuel security, in particular the availability of natural gas during the winter peak periods, as the region’s greatest risk to power system reliability.  The report makes clear that this is a very real risk for New England.  However, we believe that the static nature of assumptions where market responses aren’t fully considered, and the specification and selection of scenarios has caused the study to overstate these risks.  The report indicates one goal is to improve the region’s understanding of these risks and to inform subsequent discussions. This memo seeks to contribute to that discussion.

Fuel security is the ability of power plants to get the fuel they need, when they need it. In recent winters, ISO-NE operators have had to deal with the challenges of fuel security.  The report identified five key fuel variables that will affect the magnitude of these fuel security risks.

These variables are first discussed, then the results of ISO-NE’s analysis, followed by commentary on issues that may cause the analysis to overstate these risks or the likely incidence of the reliability events (e.g., load shedding and other less severe emergency actions such as public requests for energy conservation) identified in the report.

ISO-NE Identified Fuel Variables

The first variable is the retirement of coal, oil, and nuclear power plants.  ISO-NE noted that by June 2021, 4,600 MW of non-natural gas-fired generation will have retired, representing more than 10% of the region’s total generating capacity including the Vermont Yankee nuclear generating station (620 MW) and the Pilgrim nuclear generating station (690 MW).  In recent winters when the supply of natural gas for New England’s generation fleet has been limited, these resources have supplied a significant portion of the grid’s energy.  (See Figure 1 below, which contrasts two days this winter.) Retirement of these facilities increases the region’s reliance on natural gas and heightens natural gas constraints, which in turn increases fuel security risks.

The second fuel variable identified in the report is the availability of LNG.  There are two primary LNG facilities that serve New England natural gas-fired generators: (1) the Distrigas facility in Everett, Massachusetts, which has a storage capability of 3.4 Bcf and vaporization capability of .7 Bcf/day and is owned and operated by Engie;[1],[2] and (2) the Canaport LNG terminal in Saint John, New Brunswick, which has a storage capability of 10 Bcf and vaporization capability of .7 Bcf/day and is owned by Repsol and Irving Oil.[3]    There is also two offshore LNG injection facilities: (1) the Northeast Gateway facility, which can inject .4 Bcf/day, but is rarely used; and (2) Neptune, which also can inject .4 Bcf/day, but has not operated since it achieved commercial operation.

The Distrigas and Canaport LNG terminals serve natural gas-fired generators in New England under a range of supply arrangements, but typically provide what is essentially a peaking supply.   With LNG a global commodity, New England buyers must compete with buyers in distant markets.   Given pipeline constraints into New England, during peak winter periods prices in New England are able to attract LNG supplies, but the short duration of these price events and limited storage capabilities of the LNG terminals do not ensure a sustained supply.   Therefore, most cargoes of LNG need to be contracted and scheduled before winter begins.  With the majority sourced from Trinidad and Tobago, once contracted the LNG won’t arrive for at least five days.  Delays from winter storms pose risks.   ISO-NE noted: “Cold snaps can result in a sudden drawdown of stored LNG, and the rapid depletion of LNG combined with the region’s limited storage facilities can challenge the region’s fuel-supply chain, particularly if outages increase the need for LNG.” (p. 16)

The third fuel variable is the supply of and maintenance of oil inventories at oil-fired and dual-fuel generation facilities.  ISO-NE notes that with the retirement of oil-fired generating units, the infrastructure – barges and tanker trucks – to supply these facilities has withered.  During a cold snap, winter storms can prevent tanker trucks from making deliveries, and federal restrictions on the number of hours drivers can drive can delay deliveries.  These logistical issues pose the greatest risk to dual-fuel facilities given that they generally have the most limited on-site fuel storage capability.  The operation of these facilities on oil is also constrained by air permits, which limit the number of hours of operation on oil.   This became an issue in New England’s recent cold snap.  Given delays in fuel deliveries from winter storms and with some generators nearing emissions limits, ISO-NE took steps to conserve fuel by “posturing” units.  Specifically, ISO-NE operated some facilities “out-of-merit” so that more economical generating units that had operating constraints would be available to operate later in the day or week.   Recent regulations by the Massachusetts Department of Environmental Protection, which are being challenged in court, would ratchet down the operation of Massachusetts fossil units over time.

A fourth variable is the increasing penetration of renewable energy resources in New England. While renewables can help accommodate some of the loss in generation from coal, oil, and nuclear facilities, renewables are also contributing to the retirement of these plants by reducing the margins available in the energy market. With the renewable resources that are experiencing the fastest growth (i.e., solar and wind) having variable output, ISO-NE notes that they do not provide the same reliable supply offered by oil, coal, and nuclear units.   Nonetheless, with renewable energy resources typically displacing natural gas-fired generation they are able to reduce electricity sector natural gas demand and the resulting natural gas constraints.

We believe that ISO-NE has significantly understated the likely contribution of renewables in two key areas: (1) no incremental on-shore wind generation is assumed in any of the scenarios; and (2) the reference case assumes no additional offshore wind beyond the Block Island Wind Project.  In addition, the reference and more renewables cases reflect solar PV penetrations that are in line with ISO-NE’s most recent solar PV forecasts, a forecast which has been increased each year since it was initially developed.  The renewable energy totals do not reflect the 254 MW of solar PV projects or the 126 MW wind project that were awarded PPAs in the New England Clean Energy RFP.[4]

The final variable is electricity imports.  The Reference Case assumed imports of 2,500 MW, with imports of 3,000 MW assumed in one scenario and 3,500 MW assumed in several scenarios.  Electricity imports reduce the reliance on natural gas and depending on their delivery profile and commitments to firm winter deliveries, can significantly enhance the reliability of supply.  Subsequent to the release of the fuel security report, Hydro-Quebec was subsequently selected in response to the Massachusetts 83D RFP to provide 9.45 TWh per year over a twenty-year term.  This indicates that the reference case and many of the scenarios are too conservative.  However, as discussed above ISO-NE did consider several scenarios with 3,500 MW of imports, which is consistent with such a contract.  A study that Power Advisory performed for the Massachusetts Clean Electricity Partnership projected that such a volume of imports would reduce New England’s natural gas requirements by about 5% by reducing the requirements for natural gas-fired generation.

ISO-NE notes that Hydro-Quebec, experiences the same or similar weather as New England, and that this is could limit its ability to export power during cold snaps when New England’s needs are most acute.[5]   The various winter deliverability provisions in the 83D RFP address this concern.  With Northern Pass project delivering 9.45 TWh per year over a transmission line with a rated capacity of 1,090 MW, the project will be base loaded.  Furthermore, Hydro-Quebec will be required to guarantee this delivery profile during the Winter Peak Period.

ISO-NE Assessment of Fuel Security Risks

 To assess the risks posed by these variables, ISO-NE evaluated the operational risks posed under various future fuel-mix scenarios.  The study consisted of 23 possible resource combinations for the winter of 2024/2025, that were tested to see if enough fuel would be available to meet demand.  ISO-NE acknowledged that these 23 scenarios were not precise predictions of the future system or operating conditions, but were meant to illustrate a range of possible future conditions and risks that could accompany a winter fuel constraint.

The 23 scenarios included: (1) a reference case, which ISO-NE characterized as incorporating likely levels of each variable if the “power system continues to evolve on its current path”; (2) eight scenarios that increase or decrease the level of just one of the five key variables to assess its relative impact; (3) two boundary cases that illustrate what would happen if either all favorable or all unfavorable levels of variables were realized simultaneously.  ISO-NE characterizes these as highly unlikely scenarios that provide outer bounds to the scenarios evaluated; (4) four combination scenarios that combine the five key variables at varying levels to represent potential future portfolios; and (5) eight outage scenarios that assume winter-long outages of four major energy or fuel sources.

In almost every scenario, the power system was unable to meet demand and maintain reliability without emergency action by grid operators. Load shedding became necessary in 19 of the 23 scenarios, in order to protect the grid. And all but 1 case, the best case, led to the use of emergency actions, including public requests for energy conservation.   This is troubling and an indication of the fuel security risks faced by New England.  Unfortunately, it is impossible to quantify how significant these risks are since there is no indication of the underlying probability of these events.   We understand that assigning probabilities to such events is difficult and close to impossible.  However, care needs to be taken when interpreting these results.  We note that one party has wrongly interpreted the study as indicating that there is more than an 80% chance that some or all of New England would face rolling blackouts.[6]

Assessment of ISO-NE Scenarios

 We believe that these scenarios overstate the fuel security risks faced by New England.   The scenarios are overly pessimistic; fail to consider the ability of ISO-NE markets to respond to such conditions; understate changes to the region’s generation mix that are likely to better allow New England avoid these system conditions; and fail to consider actions that the region and ISO-NE could take to respond to winter-long outages of critical elements of New England’s energy infrastructure.

First of all, ISO-NE notes that the study did not consider prices, but it did “assume that the electricity and fuel markets send price signals sufficient to make full use of the existing electricity and fuel infrastructure as needed” (p. 20). However, in many scenarios the study made static assumptions regarding fuel supply availability.  For example, in the reference case it assumed that (1) dual-fuel facilities would have their oil tanks filled only twice; (2) the maximum LNG available was 1 Bcf/day; and (3) imports were limited to 2,500 MW, with an additional 500 MW available from emergency actions.  In the reference case, Operating Procedure No. 4 (OP 4), a series of increasingly significant actions that are called to balance supply and demand, would be called for 165 hours, with 53 hours when 10-minute operating reserve would be depleted.   Under these conditions, ISO-NE energy prices can be expected to be at a level that attracts imports and additional LNG supplies and assures a high utilization of available LNG.  Furthermore, the ISO-NE study indicates that system operating conditions become progressively dire as oil inventories decline.  This suggests that there would be a clear signal to the markets to maximize the use of imports and LNG, very likely at levels that are higher than are assumed in many of these scenarios.  Furthermore, there is also a longer-term price signal that has not been adequately considered in the study that is likely to influence the level of retirements.  The ISO-NE study is a snap shot of the 2024-25 winter.  If the conditions portrayed in the operational fuel-security analysis are to occur, one would expect that there would be similar, but less severe price events in prior years that would support the continued operation of oil units that are able to respond to such events.  We believe that by failing to consider the strength of this price signal and the response that it engenders the study overstates fuel security risks.

With respect to the reference case, we believe that ISO-NE’s characterization that the case reflects the power system continuing to evolve on its current path is inaccurate.  The reference case reflects a largely static case, with over seven years little to no evolution of critical variables that would help to mitigate these fuel security risks.  As discussed, the reference case fails to account for: (1) 380 MW of solar and wind projects that have been selected in the New England Clean Energy RFP; (2) the 9.45 TWh per year of hydroelectricity that was selected in the 83D RFP;[7] and (3) the prospect of any additional OSW projects being in-service as of 2024-25 winter.  We estimate that these resources will produce almost 12 TWh of energy, resulting in an increase in renewable and clean energy supply of about 10% of ISO-NE’s forecast energy demand for 2024.

While not an element of just the reference case, but an element of analysis that affects all the scenarios is the projected growth in natural gas demand for New England gas distribution companies of just under 2% per year.  While some utilities are growing sale volumes by expanding their customer bases, we believe that energy conservation could be used to reduce this rate of growth.  Furthermore, the study only considers pipeline expansions that were recently completed or are underway.

Second, with respect to eight outage scenarios that reflect winter-long outages of four major fuel or energy sources, these as well are unduly pessimistic.   The outages evaluated were the winter-long loss of: (1) two units at Millstone representing 2,100 MW; (2) the loss of Canaport LNG; (3) the loss of Distrigas LNG; and (4) an outage at a compressor reducing natural gas deliveries by 1.2 Bcf/day.

The loss of both units at Millstone for the entire winter season is extremely unlikely.  These are two separate units, which for safety reasons have separate facilities.  While they share transmission facilities, under Nuclear Regulatory Commission rules there is redundancy and the loss of a transmission corridor as a result of a catastrophic event would result in an immediate mobilization of resources to replace the transmission facilities within the corridor.

With respect to the loss of the Canaport and Distrigas facilities, both have multiple vaporizers that provide redundant vaporization capacity.  A season long loss of these LNG facilities would appear to be only possible through a failure of the LNG storage tank, which would represent a major safety threat and as such is likely to be appropriately monitored with adequate engineering safeguards.  However, the Distrigas facility has two storage tanks and the Canaport facility three.  While there could be temporary damage to offloading facilities that would preclude deliveries.  It is difficult to envision damage so severe that it would remove these facilities from service for an entire season.  Finally, New England has two offshore LNG facilities that each have a delivery capability of .4 Bcf/day.  One of these is rarely used and then other has been never used.  With the loss of either of these major LNG facilities, we would expect that these offshore facilities could be used to fill the void.  We don’t believe that this was adequately considered by the ISO-NE study.

The fourth winter long outage considered by ISO-NE is the loss of a compressor station for an entire season.  This outage event is also highly improbable.  The pipelines that serve New England have multiple compressor stations and the loss of any one compressor station is unlikely to have such a profound effect on natural gas deliveries.  The natural gas pipelines that serve New England have been gradually expanded since they first entered commercial operation.  The net effect of this is redundancy in the design of these systems such that the loss of any single compressor is unlikely to have such a profound impact.   ISO-NE indicates that the Algonquin pipeline provides about 1.91 Bcf/day, such that a 1.2 Bcf/day reduction would represent 63% of the pipeline’s total delivery capability.  We believe it highly unlikely that the loss of such a compressor would be sustained for the entire season.  Furthermore, as acknowledged by ISO-NE with the loss of such a large volume of pipeline capacity one would expect LNG deliveries to increase including the utilization of the offshore LNG facilities.

In sum, we believe these season long outages to be highly unlikely and as such not reasonable scenarios.  An omission in the ISO-NE study is any reasonable level of policy response to what would presumably be viewed as a catastrophic event that likely engender a response to avoid the adverse consequences that ISO-NE’s study identifies.  We would expect such responses to include supporting the mobilization of existing offshore LNG unloading facilities, temporary relaxation of air permit limits of fossil generating units and potentially the mobilization of energy storage similar to what occurred in southern California after the Aliso Canyon natural gas leak.

A PDF version of this report is available here.

John Dalton, President and Tyler Sellner, Researcher, Power Advisory LLC

 

[1] Mystic units 8 and 9 are directly connected with the Everett LNG terminal, which supplies their natural gas requirements.

[2] In its report ISO-NE indicates that the Distrigas project has a maximum injection of 0.435 Bcf/d into the interstate pipeline system and the local gas utility system”.  The Distrigas project has an additional .3 Bcf/day interconnection with Mystic station, such that the full vaporization capability of the Distrigas project can be utilized and a significant portion is dedicated to power generation.

[3] The Canaport LNG terminal is connected to the New Brunswick Pipeline and then the Maritimes & Northeast Pipeline, which in turn can deliver natural gas into Maine and southern New England markets.

[4] While this wind project is in New York State, the PPA calls for the delivery of the energy and RECs to the ISO-NE grid such that this renewable generation will be displacing other New England generation.

[5] The report indicated that this study does not attempt to quantify these effects.

[6] https://commonwealthmagazine.org/energy/energy-study-draws-divergent-reactions/

[7] We understand that we could be considered as being overly critical and applying hindsight given that the results of the 83D RFP were released more than a week after the ISO-NE study.  However, the 83D RFP clearly communicated a goal of contracting 9.45 TWh of clean energy.