Author Archives: Carson Robers

Review of Atlantic Offshore Wind Procurement Policy and Developments

Over the last year major commitments have been made with respect to the US offshore wind (OSW) market. From only 30 MW operating, approximately 2,000 MW has been contracted and a cumulative +10 GW of installed capacity is now expected by the early 2030s. The growing interest in OSW has been concentrated in the Atlantic, particularly the Northeast which has the strongest state policies for OSW. An indicative schedule of this development by state is presented in the figure below.[1] Power Advisory then provides a high-level review of the procurement processes in New England, New York, and New Jersey as the primary markets, representing about 80% of this total.

New England

As part of the 2016 Act to Promote Energy Diversity, Massachusetts established a procurement target of 1,600 MW of offshore wind by 2030. The first solicitation for OSW proposals, referred to as the 2017 Section 83C RFP, resulted in the selection of 800 MW from Vineyard Wind in May 2018. The contracts for this project are currently before the Massachusetts Department of Public Utilities with a real levelized price for energy and RECs of $64.97 per MWh (2017$).[1]  On July 31st, An Act to Advance Clean Energy was passed, instructing a cost benefit analysis to be completed for an additional 1,600 MW of offshore wind by 2035 and specified that the Department of Energy Resources “may require said additional solicitation and procurements.” Governor Baker, who was recently reelected, signed a pledge to complete this study during the campaign. Given the compelling economics of the long-term contracts secured through the first Massachusetts OSW solicitation we believe that this effectively doubles the Commonwealth’s OSW goal to 3.2 GW by 2035 without the need for additional legislative authority.

In May, Rhode Island selected 400 MW from Deepwater Wind’s Revolution Wind Project.[2] Deepwater Wind has entered into contract negotiations with National Grid. An executed contract for energy and RECs is expected to be filed with the Rhode Island Public Utilities Commission by the end the year.

Connecticut also selected 200 MW from Deepwater Wind’s Revolution Wind Project. The wind farm will be part of the same project selected by Rhode Island, but will deliver electricity directly to the state via a separate export cable. On September 14th, Connecticut closed an RFP for 12 TWh of zero-carbon energy which is said to have received offshore wind proposals. The evaluation phase will be completed in Q4 2018/Q1 2019. Additional opportunities for OSW contracts from Connecticut are uncertain.

The southern New England states have each approached OSW with long-term contracts for bundled energy and RECs, consistent with contracting practice for other clean energy resources in the region. The retention of capacity value by developers provides an incentive for suppliers to maximize that value through efficient operating practices.  The PPA requires the seller to participate in the Forward Capacity Market so that this value can be considered by ISO-NE and ultimately realized by customers.

Evaluation of OSW proposals in New England has focused on economic benefits. For example, the evaluation procedure used in the 2017 Section 83C RFP was based on a 75/25 split between economic benefits and qualitative considerations. Direct economic benefits were assessed based on comparing the proposal price and any required transmission upgrade costs with its direct economic benefits as measured on the basis of the net present value of energy (by LMP) and the value of Class I RECs. Four indirect proposal benefits of wholesale energy price savings, RPS compliance cost savings, incremental greenhouse gas reduction compliance savings, and economic impact of resource winter firmness were also considered. Qualitative considerations included: (1) siting, permitting, and project schedule risks; (2) reliability benefits; (3) other benefits, costs and project risks; (4) environmental impacts from siting; and (5) economic development benefits to the state.

New York

Governor Cuomo established a goal of 2,400 MW of OSW by 2030 in 2017. Offshore wind is a key component of the state’s Clean Energy Standard (CES) of 50% clean energy by 2030. The Long Island Power Authority (LIPA) 2015 South Fork RFP that was open to all resources resulted in the selection of Deepwater’s 97 MW South Fork Wind Farm. This project is expected to come online in 2022 and counts towards the state’s 2.4 GW goal.

NYSERDA released a final RFP to solicit 800 MW or more of offshore wind today (November 8, 2018). Bids are due February 14, 2019. The remainder of the 2,400 MW goal (Phase II) will be procured at a later date. New York has also begun securing stakeholder input on the appropriate transmission development framework for Phase II.

NYSERDA is employing a scoring system that considers price and non-price factors, with each project scored according to a 100-point scale based on three criteria:

  1. Project Viability: 10 points – Non-Price Evaluation
  2. New York Economic Benefits: 20 points – Non-Price Evaluation
  3. Offer Strike Prices: 70 points – Price Evaluation

Project viability is assessed in terms of whether the proposed project can reasonably be expected to be in service on or before the proposed Commercial Operation Date. To maximize the score received, proposers must demonstrate that project development plans are mature, and technically and logistically feasible, that they have sufficient experience, expertise, and financial resources to execute the development plans in a commercially reasonable and timely manner. New York Economic Benefits are measured in terms of three considerations: (1) project-specific spending and job creation in New York State; (2) investment in offshore wind-related supply chain and infrastructure development in New York State; and (3) activities that provide opportunities for the New York offshore wind supply chain, workforce, and research and development.

Offer strike prices are assessed in terms of a: (1) an Index OREC price and; (2) a Fixed OREC price. The Index OREC price will vary monthly based on the value of Index OREC Strike Price specified minus the monthly Reference Energy Price and the monthly Reference Capacity Price. The Fixed OREC price is based on the fixed price specified by the proposer. In essence, the Index OREC price is a contract for difference that considers relevant energy and capacity prices, thereby providing a market price hedge that should support more attractive financing terms than the Fixed OREC.[3]  The Index OREC price will be given a weight of 0.9 and the fixed OREC price a weight of 0.1 to establish the weighted strike price for each proposal.  Either OREC strike price option can be chosen at NYSERDA’s discretion. NYSERDA’s decision will be based upon its projection of the relative costs of the Fixed ORECs and Index ORECs compared to the relative price risks of the Fixed ORECs and Index ORECs over the life of the contract.

If the Fixed OREC price option is chosen, the OREC price will remain for the entirety of the contact length, 20 to 25 years. If the Index OREC is chosen, the OREC will remain for the entirety of the contract unless the Index OREC price is invalidated.

New Jersey

The Offshore Wind Economic Development Act authorized the New Jersey Board of Public Utilities (BPU) to establish an OREC program in 2010. After almost eight years of stalled implementation and development under the previous administration, newly sworn in Governor Murphy signed Executive Order #8 (EO8) on January 31st, 2018. E08 directed all New Jersey agencies with responsibilities under the OWEDA to fully implement it in order to meet a goal of obtaining 3,500 MW from OSW by 2030.

On September 20, 2018 New Jersey opened its first “application” for 1,100 MW of OSW. This will be the nation’s largest OSW solicitation to date. The application window will close on December 28, 2018, with the BPU required to act on the proposals by July 1st, 2019. The goal of the compressed procurement timeline is to maximize the ability of developers to capture the expiring federal ITC and increase the attendant economic benefits that can be realized by the state from the development of the regional industry. Governor Murphy has also directed a target of 2020 and 2022 for two additional BPU solicitations of 1,200 MW to reach the overall goal of 3,500 MW. Identifying these second and third large, near-term procurements is also intended to induce the OSW supply chain to locate in New Jersey.

Separately, EDF Renewables and Fisherman’s Energy have submitted an OREC application to the BPU for approval of the 24 MW Nautilus OSW farm with a planned COD in 2020.

The OREC structure in New Jersey differs from the typical Renewable Portfolio Standard (RPS) programs (ex. RECs, SRECs), which provide an additional source of revenue beyond energy and capacity. The BPU’s OREC Funding Mechanism is largely based on the procurement of a bundled energy, environmental attribute and capacity product. The use of an OREC ultimately adds complexity with respect to the administration of the ORECs and risk to OSW developers (e.g., variances between actual and forecast OSW output) and in Power Advisory’s opinion could be more simply administered with stronger performance incentives with a PPA that procured energy and environmental attributes. However, this is the framework that was legislatively directed and is expected to be used for all three upcoming procurements.

Rather that issue a formal request for proposals the New Jersey BPU issued Guidelines for applications for the sale of ORECs.[4] These guidelines identify the requirements for applications and outline the six criteria that the BPU will use to rank proposals.  These six criteria are:

(1)   OREC Purchase Price, which can be fixed or escalating;

(2)   Economic impacts, which includes, the number of jobs created, increases in wages, taxes receipts and state gross product for each MW of capacity constructed;

(3)   Ratepayer impacts, which considers the average increase in residential and commercial customer bills along with the timing of any rate impacts;

(4)   Environmental impacts, which includes the net reductions of pollutants for each MWh generated and the feasibility and strength of the applicant’s plan to minimize environmental impacts created by project construction and operation;

(5)   The strength of guarantees for economic impacts, which considers all measures proposed to assure that claimed benefits will materialize as well as plans for maximizing revenue from the sales of energy, capacity and ancillary services; and

(6)    Likelihood of successful commercial operation, which includes feasibility of project timelines, permitting plans, equipment and labor supply plans and the current progress displayed in achieving these plans.

There’s very little transparency regarding the evaluation process and how tradeoffs regarding these six criteria will be assessed.  The Guidelines indicate that “ranking and weighting of the six criteria by the BPU will reflect the goals of the solicitation especially as stated in the Governor’s Executive Order No. 8.” Based on our experience we believe that this lack of detail regarding how these criteria as well as tradeoffs among these criteria will be assessed, may hamper the ability of proponents to craft proposals that best satisfy New Jersey’s objectives.

Power Advisory would welcome the opportunity to assist clients in understanding the opportunities presented by the emerging US offshore wind industry.


A PDF of this update is available here.

[1] Note the schedule represents anticipated commercial operation date versus when the capacity is expected to be solicited. For Massachusetts, Vineyard Wind was originally proposed as two 400 MW phases coming into service in late 2021 and 2022, but in its Supplemental Draft Environmental Impact Report Vineyard Wind announced that it would construct the full 800 MW simultaneously and commission the project in mid-2022.

[1] This price escalates at 2.5% per annum and the project owner retains revenues from ISO-NE’s Forward Capacity market.

[2] On October 8th Ørsted announced that it was acquiring Deepwater Wind and its portfolio of 5 PPAs representing 810 MW for $510 million.

[3] An assumption must be made regarding the UCAP Production Factor so that the project nameplate capacity can be converted to UCAP.  NYSERDA allows a proponent to use a default UCAP Production Factor of 38% consistent with the NYISO’s Installed Capacity Manual or to specify a project-specific value. These values will be constant throughout the contract term. The ability to specify an alternative UCAP Production Factor presents an opportunity for proponents to change the risk/reward profile and as such warrants analysis.

[4] Guidelines for Application Submission for Proposed Offshore Wind Facilities


Competitive Implications of Ørsted’s Acquisition of Deepwater Wind

Yesterday, Ørsted A/S (Ørsted) announced that it agreed to acquire Deepwater Wind (Deepwater) from D.E. Shaw & Co. LP for $510 million. With this acquisition Ørsted, who was unsuccessful in the various New England competitive procurement processes, will get access to Deepwater’s 5 PPAs and 810 MW contracted project development portfolio. The transaction is subject to review by US competition authorities, the US Department of Justice (DOJ) and the Federal Trade Commission (FTC). Given the nascent state of the US OSW industry the acquisition of one of the US industry leaders by the world’s largest OSW project developer may raise some competitive concerns, particularly when the lease holdings of the combined company are considered in several relevant geographic markets.

Specifically, Ørsted will have ownership interests in two of the three existing BOEM leases in the Rhode Island/Massachusetts Wind Energy Areas (WEAs) through its Bay State Wind partnership with Eversource Energy and its acquisition of Deepwater. In addition, Ørsted will have development rights to two of the three existing leases off the coast of New Jersey as result of its Ocean Wind project and with the acquisition of Deepwater’s 50% interest in the Garden State Offshore Energy project, a joint venture with Public Service Electric & Gas that holds the rights to a BOEM lease off the coast of Delaware and New Jersey. (See Figure 1 below.)
A critical issue with respect to the assessment of the competitive implications of mergers is defining the market, which considers the relevant products and geographic definition of the market. The geographic definition of the market considers the ability of competitors to compete effectively with the merged entity recognizing that there is a cost to accessing a more distant market (e.g., for OSW the cost of undersea transmission cables or transmission service).

The Rhode Island/Massachusetts WEAs offer more attractive wind regimes than the New York (NY) or New Jersey (NJ) WEAs, suggesting that it may be difficult for leaseholders in NY or NU WEAs (e.g., Equinor) to compete effectively with the RI/MA leaseholders. The competitiveness of the New England OSW market will be enhanced when BOEM issues the two additional MA leases that are scheduled for auction in early 2019. However, the ability of these new leaseholders to compete in the forthcoming Massachusetts 83C OSW RFP may be constrained by the relative immaturity of the corresponding projects and the fact that Massachusetts OSW RFPs typically considered the development status of projects in the evaluation and project scoring.

Figure 1: Ørsted US Offshore Wind Portfolio

A PDF version of this memo is available here.

Review of NYSERDA Request for Proposals for Purchase of Offshore Wind Renewable Energy Certificates

Last week, NYSERDA issued a draft Request for Proposals (RFP) to solicit 200 MW to 800 MW of offshore wind with proposals due in the Winter 2019. The draft RFP is in response to New York State’s Offshore Wind Master Plan that encourages the development of 2,400 MW of offshore wind by 2030.  The offshore wind projects will be procured in two phases to reach the 2,400 MW goal. Phase 1 entails procuring Offshore Wind Renewable Energy Certificates (ORECs) associated with approximately 800 MW of offshore wind. The New York Public Service Commission Offshore Wind Order authorizing NYSERDA to undertake this procurement further permits NYSERDA to award more than 800 MW in this first round of the Phase 1 solicitation if sufficient attractive offers are received.  The Phase 2 procurement will build on Phase 1 framework and seek to procure the remaining offshore wind energy to reach the 2,400 MW goal.

NYSERDA is employing a scoring system that considers price and non-price factors, with each project scored according to a 100-point scale based on three criteria:

  1. Project Viability: 10 points – Non-Price Evaluation
  2. New York Economic Benefits: 20 points – Non-Price Evaluation
  3. Offer Strike Prices: 70 points – Price Evaluation

The non-price evaluation components will be evaluated by a scoring committee.  Project viability will be assessed in terms of whether the proposed project can reasonably be expected to be in service on or before the proposed Commercial Operation Date. To maximize the score received, proposers must demonstrate that project development plans are mature, and technically and logistically feasible, that they have sufficient experience, expertise, and financial resources to execute the development plans in a commercially reasonable and timely manner.  New York Economic Benefits will be measured in terms of three considerations: (1) project-specific spending and job creation in New York State; (2) investment in offshore wind-related supply chain and infrastructure development in New York State; and (3) activities that provide opportunities for the New York offshore wind supply chain, workforce, and research and development.

Offer strike prices will be assessed in terms of a: (1) an index OREC price and; (2) a fixed OREC price. The index OREC price will vary monthly based on the value of Index OREC Strike Price specified minus the monthly Reference Energy Price and the monthly Reference Capacity Price. The fixed OREC price is based on the fixed price specified by the proposer.  In essence, the index OREC price is a contract for difference that considers relevant energy and capacity prices. The index OREC price will be given a weight of 0.9 and the fixed OREC price a weight of 0.1 to establish the weighted strike price for each proposal.   Either OREC strike price option can be chosen at NYSERDA’s discretion. NYSERDA’s decision will be based upon its projection of the relative costs of the Fixed ORECs and Index ORECs over the life of the contract compared to the relative price risks of the Fixed ORECs and Index ORECs over the life of the contract.

If the fixed OREC price option is chosen, the OREC price will remain for the entirety of the contact length. If the index OREC is chosen, the OREC will remain for the entirety of the contract unless the Index OREC price is invalidated.

This draft RFP will be open to public comment until Friday, October 5th, 2018. Subsequently, NYSERDA will review the public comments; refine the draft RFP; and publish a final RFP in Q4 of 2018.

A PDF version of this update is available here.

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

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

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 canadian assets

NextEra Energy Canadian Portfolio – Solar

solar energy canadian portfolio

NextEra Energy Canadian Portfolio – Wind

wind energy canadian portfolio

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.


[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.