Author Archives: Carson Robers

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.

[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.

Review of 83D Selection: Northern Pass Transmission, Hydro

Today, the Massachusetts investor-owned electric distribution companies in coordination with the Department of Energy Resources (DOER) announced the completion of the evaluation of responses to the Massachusetts Clean Energy Generation RFP (83D RFP). Northern Pass Transmission, Hydro was selected as the sole winning bid; representing a purchase of 9.45 TWh per year. Eversource Energy and Hydro-Québec Production (HQ) are the proponents of Northern Pass Transmission (NPT), which will deliver 1,090 MW of hydropower to the region.

Overview of Northern Pass Transmission

The NPT project is a 320 kV 192-mile transmission line from the Quebec border to Deerfield, New Hampshire where it will connect to the rest of the New England grid.  With a capacity rating of 1,090 MW, the project will have a capacity factor of +98%. The line will be developed in two segments – a 158 mile HVDC partially overhead and partially buried section from Stewartstown, NH to Franklin, NH and a 34 mile HVAC overhead line from a new substation in Franklin, NH to the southern terminus. Up to 80% of this construction will take place within existing right of way. Having made considerable progress on the development of the transmission and with the HQ hydroelectric facilities already constructed or under construction, the project has been touted by the developers as “shovel-ready”, with a 2020 in-service date.

One challenge that remains for NPT is receiving final permitting and regulatory approvals from:

  • the New Hampshire Siting Evaluation Committee (NH SEC);
  • Army Corps of Engineers (Section 404 permit);
  • and the Federal Energy Regulatory Commission (rate authority and firm transmission capacity agreement approval).

This is especially the case for the NH SEC, given the delays in receiving a permit from the Committee and the substantial public opposition NPT has faced in Northern New Hampshire. A twelve-day period of public deliberations will begin on January 30th for the NH SEC, leading to an oral decision by February 23, 2018. The project has already received a Presidential Permit from the U.S. Department of Energy and key Canadian permits.

Hydro Québec’s Position in New England

 Overall HQ participated in six of the forty-six submissions to the 83D RFP, including three of the proposed transmission projects with offers of hydro with and without 300 MW of Quebec wind. Already HQ supplies about 10% of New England’s annual energy requirements and with the addition of this project will be providing upwards of 17%.

A PDF version of this update is available here.

Review of New York State Clean Energy Proposals

To: Clients and Colleagues
From: John Dalton, President & Margaret Blagbrough, Consultant, Power Advisory LLC

On January 2, New York Governor Andrew Cuomo unveiled sweeping clean energy proposals touching every aspect of the renewable energy sector. The main purpose of these proposals is to allow the state to fight climate change and protect the environment, while also creating jobs in the renewable energy sector. The set of proposals, titled the 2018 Clean Energy Jobs and Climate Agenda, is in addition to ambitious clean energy goals already mandated in the state, including the mandate to generate 50 percent of the state’s electricity from renewable energy sources by 2030.

A major piece of this agenda focuses on energy storage. Governor Cuomo plans to add 1,500 megawatts of energy storage by 2020, the largest commitment of this type per capita by any state. In order to achieve this goal, the Governor is proposing a commitment of $200 million from the NY Green Bank for energy storage investments. Additionally, he is directing the New York State Energy and Research Development Authority (NYSERDA) to invest $60 million through storage pilots to reduce barriers for deploying energy storage. This will pave the way for utility procurements of energy storage in 2018. Additionally, energy storage will be incorporated into the criteria for future large scale renewable procurements.

The Governor is also calling for a procurement of at least 800 megawatts of offshore wind generation between two solicitations issued in 2018 and 2019. These will be the first procurements in a set of staggered procurements to reach the state target of 2.4 gigawatts of offshore wind by 2030, established last year. Governor Cuomo is directing NYSERDA to invest in job training in the offshore wind industry and to determine the most promising offshore wind port infrastructure investments. In October of 2017, New York State submitted an identified Area of Consideration for new wind lease areas to the Bureau of Ocean Energy Management (BOEM). New York requested that BOEM identify and lease at least four new wind energy areas, each accommodating at least 800 megawatts of offshore wind, within the Area of Consideration.

The Governor also addressed energy efficiency, calling on stakeholders to propose a far-reaching energy efficiency initiative by April 22, 2018, propose a 2025 energy efficiency target, and establish appliance efficiency standards. Other agenda items include: the development of a zero-cost solar program for 10,000 low-income residents; expanding the Regional Greenhouse Gas Initiative (RGGI) to other states and to broaden regulations to include smaller and less efficient peaking plants; and phase out all coal-fired power plants in New York by 2020.

Power Advisory would welcome the opportunity to assist clients in assessing opportunities in the New York renewable energy market.

A PDF version of this report is available here.

Review of Massachusetts Offshore Wind Energy RFP (83C) Proposals

To: Clients and Colleagues
From: John Dalton, President; Margaret Blagbrough, Consultant; Michael Ernst, Executive Advisor; Power Advisory LLC

On December 20, 2017, the Massachusetts investor-owned electric distribution companies (Distribution Companies) in coordination with the Massachusetts Department of Energy Resources (DOER) received three proposals for offshore wind energy generation projects, in response to the RFP they issued for 400 MW (and up to 800 MW) of wind energy under long-term contracts. This procurement is the first in a series of competitive solicitations under the state’s 2016 Act to Promote Energy Diversity mandate for 1,600 MW of offshore wind (OSW) by June 30, 2027. Winners of this first procurement will be announced on April 23, 2018. The bidders who submitted proposals are those that hold existing Bureau of Ocean Energy Management (BOEM) Massachusetts or Massachusetts/Rhode Island offshore leases: Deepwater Wind, Bay State Wind (Ørsted and Eversource Energy), and Vineyard Wind (Avangrid Renewables and Copenhagen Infrastructure Partners). The figure below shows the locations of each of the proponents’ lease areas.

Proposals are required for the target capacity of 400 MW, but additional proposals between 200 MW and 800 MW are allowed and were submitted. Any chosen proposal over 400 MW must be superior and provide significantly more economic benefits to Massachusetts ratepayers. Each proponent must include a proposal for a generator lead line to deliver offshore wind to the corresponding onshore ISO-New England (ISO-NE) Pool Transmission Facilities (PTF). Additionally, proponents must submit a proposal for an expandable transmission network providing nondiscriminatory access for all offshore wind facilities.

Proponents will be evaluated in three stages. In the first stage, proposals will be evaluated to see if they meet eligibility and threshold criteria. Proposals that meet the basic requirements of stage one will be evaluated based on the costs and benefits of the project in stage two. Quantitative evaluation criteria in this stage include direct costs and benefits and other costs and benefits to retail customers. Qualitative evaluation criteria will include: (1) the siting, permitting and project schedule; (2) reliability benefits; (3) benefits, costs, and contract risk; (4) environmental impacts from siting; and (5) economic benefits to the Commonwealth. In the third stage, the Evaluation Team will further evaluate proposals to ensure that they are the most cost-effective solutions for ratepayers and that they will provide reliable renewable energy for the long-term.

Confidential information including pricing has been redacted from the public versions of bids we have reviewed and summarized below.

Bay State Wind

Bay State Wind, the partnership between Ørsted and Eversource, proposed either a 400 MW or 800 MW wind farm 25 miles off of New Bedford, MA. The 400 MW project would be paired with a 30 MW/ 60 MWh battery storage facility, while the 800 MW project would be paired with a 55 MW/110 MWh battery storage facility. Ørsted, formerly DONG Energy, is the world’s largest offshore wind developer. Ørsted has constructed 3.8 GW of offshore wind capacity over the past 25 years and has another 5 GW under construction. Eversource is New England’s largest energy provider and is slated to develop and construct the project’s onshore transmission system.

The project would use New Bedford as the construction area and the base of its operations and maintenance throughout the project’s lifetime. Brayton Point in Somerset, MA will be the grid connection location for the project and the home of the battery storage facility.  The project would result in the development of the first Jones Act compliant installation and transportation vessels.

In their proposal, the company stated that they are the furthest along in the ISO-NE interconnection queue process compared to the other two eligible bidders. Their completed Feasibility Study shows that either of the two projects can interconnect into Brayton Point without any system upgrades. The timeline of the project was not publicly released.

Bay State Wind asserts that the scale of its proposed projects will better allow Massachusetts to become “the hub of the offshore wind industry in Massachusetts” and that Ørsted’s “develop, build, own, and operate” model ensures that it is vested in the long-term success of its wind farms, compared to other developers.

Deepwater Wind

Deepwater Wind proposed either a 200 MW or 400 MW wind farm, called Revolution Wind, with a commercial operation date (COD) in 2023.  Deepwater Wind also appears to have submitted an expandable offer, the details of which were redacted.  It proposed an initial 144 MW phase of the project in response to Massachusetts’ 83D solicitation for 9.45 TWh of clean energy. The state will announce the winners of that RFP on January 25, 2018.

In contrast to Bay State Wind and Vineyard Wind, Deepwater Wind’s value proposition is focused on the economies offered by the gradual and sequenced development of the offshore wind industry from smaller to larger wind farms.  This strategy leverages off existing its existing OSW project and contract to develop another OSW project. Deepwater Wind built the 30 MW Block Island Wind Farm in 2015 and 2016 and has a contract with Long Island Power Authority to build the 90 MW South Fork Wind Farm foundations in 2021 and install the turbines in 2022.  Deepwater Wind proposes to build the Revolution Wind foundations in 2022 and install the turbines in 2023.  We believe that its redacted expandable proposal provides for subsequent phases of the Revolution Wind project to further develop the OSW supply chain.  Deepwater Wind asserts that its approach avoids a “boom-bust cycle.” Presumably, the pricing for the expandable offer reflects projected economies that will be realized from the development of the OSW supply chain.

The proposal includes an agreement with the Northfield Mountain Generating Station, a pumped-storage hydroelectric plant in Northfield, MA.  If the Distribution Companies select this Storage Feature, the facility would store energy generated by the wind farm during off-peak hours and deliver energy to electric utilities during on-peak hours.

Deepwater Wind also partnered with GridAmerica Holdings Inc. (a National Grid subsidiary) to develop the Project interconnection and an offshore transmission network. The network could support up to 1,600 MW of wind energy for Revolution Wind and future wind farms. Revolution Wind would connect to the Brayton Point substation in Somerset, MA (1,000 MW) and to Davisville substation in North Kingstown, RI (600 MW), and will be operated and maintained in New Bedford, MA. The project is set to begin construction in 2022 if approved, and commence operations in 2023. Deepwater Wind is the developer of the Block Island Wind Farm off the coast of Rhode Island, which is the United States’ first commercial offshore wind farm and another GridAmerica affiliate constructed the Block Island Transmission System for the interconnection into Rhode Island.

Vineyard Wind

Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, submitted proposals for either a 400 MW or 800 MW wind farm. For the 400 MW project, the generation would be bundled with Vineyard Connector 1, which is an 800 MW expandable transmission project. Vineyard Wind Connector 2 is an optional phase two of the expandable transmission project, which would have another 800 MW of capacity. For their 800 MW project, Vineyard Wind is bundling Vineyard Wind 1 and Vineyard Wind 2, each a combined generation and transmission project with individual capacities of 400 MW. An optional phase would be Vineyard Wind Connector 2, an expandable transmission project, which would have another 800 MW of capacity. The lines would interconnect to Barnstable, MA, and West Barnstable, MA.  Vineyard Wind would use Vineyard Haven, MA as its site for the operations and maintenance port during the life of the project.

The 400 MW project would have a COD of December 2021, which Vineyard Wind claims to be the earliest possible project in Massachusetts given its position as the “most mature and most advanced” large scale wind project as evidenced by its recent December 2017 applications for a federal Construction and Operations Plan with BOEM and with the state Energy Facilities Siting Board. The second 400 MW would be commissioned in 2022.  Vineyard Wind has a Community Benefits Agreement and letters of support from local fishermen and all six towns on Martha’s Vineyard plus Nantucket.

Vineyard Wind would establish a $15 million Massachusetts Offshore Wind Accelerator Program to support upgrade of local ports for staging, support set-up costs for supply chain companies, training local workers and investing in new technologies to protect marine species.  Vineyard Wind would also establish a self-sustaining Resiliency and Affordability Fund that invests in local energy storage facilities.

Avangrid, Inc. owns regulated utilities and renewable energy assets throughout the United States. However, none of these regulated assets are Massachusetts utilities. * Avangrid Renewables, another one of Avangrid’s subsidiaries, recently won BOEM’s competitive lease auction for a wind lease area off the coast of North Carolina. Copenhagen Infrastructure Partners is a fund management company that has developed and invested in large offshore wind projects worldwide.

Power Advisory would welcome the opportunity to assist clients in assessing opportunities in the US offshore wind market, especially the upcoming BOEM Massachusetts and NY lease sale auctions, submission of comments on the 83C RFP, and participation in subsequent solicitations.

A PDF version of the report is available here.

*A previous version of this report incorrectly identified Until as part of Avangrid’s portfolio. Avangrid does not have an ownership stake in Until, nor any other Massachusetts electric utility.

Alberta REP 1 Results – Summary and Commentary

December 14, 2017

To:       Power Advisory LLC Clients and Contacts

From:   Sarah Simmons, Jason Chee-Aloy, and Kris Aksomitis, Power Advisory LLC

Yesterday, the Alberta Electricity System Operator (AESO) announced the results and contract awards from their first Request for Proposals (RFP) under their new Renewable Electricity Program (REP), known as REP 1.  The results and contract awards are available on the AESO’s website: https://www.aeso.ca/market/renewable-electricity-program/rep-round-1-results/.

This announcement is a culmination of efforts that began in 2015 following the release of the Government of Alberta’s (GOA’s) Climate Leadership Plan (CLP), which called for the addition of 5,000 MW of new renewable generation capacity by 2030 as part of a plan to supply 30% of Alberta’s electricity needs from renewable energy.

By all accounts, REP 1 was expected to be a highly competitive procurement – and the results of yesterday’s announcement has delivered on that expectation.  Exceeding the REP 1 procurement target by nearly 200 MW, a total of just under 600 MW of wind generation was procured, with a weighted average contract price of just over $37/MWh:

  • Capital Power’s 202 MW Whitla;
  • EDP Renewable’s 248 MW Sharp Hills;
  • Enel Green Power’s 115 MW Riverview; and
  • Enel Green Power’s 31 MW Phase 2 of Castle Rock Ridge.

With contract prices ranging between $30.90/MWh to $43.30/MWh, the energy industry in Alberta, and across Canada, will take note and time to reflect on what these results mean going forward.  These prices are record setting for Canadian wind generation projects.

The following summary and commentary reflects on the outcomes of yesterday’s announcement by providing background on the competition and reflects on the next steps the AESO may consider for future rounds of the REP.

Contract Price

Originally the CLP called for a cap of $35/MWh for Renewable Energy Credits (RECs).  At the start of the consultation with industry regarding the design of the REP in 2016, the AESO had initially considered a simple, fixed-price contract approach for RECs.  In other words, the proposed a fixed-price REC would be paid on top of wholesale energy market revenues.   While the approach was considered to address the objective of maintaining the impact of market price signals and would be compatible with a price collar (i.e. the cap), the AESO ultimately adopted an Indexed-REC approach as outlined in their recommendation report to the GOA in May 2016.  Given the variability in predicting cash-flows from wholesale market revenues, an Indexed-REC was adopted to help ensure that the overall unit price for contracted renewable generation was as low as possible.  The Indexed-REC provides a predictable revenue stream, which unlocked wide-ranging industry participation by enabling broader debt-financing options.  This approach also provides protection to Alberta’s electricity customers, who would see a benefit if pool prices are greater than the contract price.

The resulting weighted average contract price of $37/MWh is indictive of the Indexed-REC price approach and the ability to put downward pressure on the costs for renewable energy projects. The decision to move to a ‘contract-for-difference’ approach not only achieved low prices by attracting relatively low-cost capital, but also reduced ratepayer exposure to higher future payments (i.e., the average contract price is lower than 2018 forward energy prices and in-line with expected wind realized prices).

Indeed, the contract prices achieved in REP 1 are notable from a national perspective.  The prices are significantly lower than the Ontario Independent Electricity System Operator’s (IESO’s) Large Renewable Procurement (LRP) in 2016 (299.5 MW of wind generation contracted at an average price of approximately $86/MWh) and Hydro Quebec Distribution RFP results from December 2014 (446.4 MW of wind generation contracted at an average price of approximately $76/MWh).  The Alberta result is more aligned with recent Power Purchase Agreement (PPA) prices in U.S. jurisdictions as illustrated the figure below from Berkley Lab.

Source:  Berkley Lab, Wind PPA Prices (https://emp.lbl.gov/wind-ppa-prices)

Successful Proponents

Two incumbents and one new entrant to Alberta’s electricity market were successful – each with an aggressive approach.

As one of Alberta’s largest electricity generators, with a fleet consisting primarily of fossil-fuel generation, Capital Power clearly made a push towards achieving their wind generation development goals for 2017.  Enel Green Power, relatively new to the Alberta market, expands upon their existing Castle Rock Ridge wind generation project which was completed in 2012, and moves forward with a new sizable project.

New to Alberta, EDP Renewables competed and won against a strong incumbency as well as other competitive would-be new entrants.

Both EDP Renewables and Enel Green Power are building upon recent successes in North American renewable generation procurements; EDP Renewables being successful in IESO’s LRP I RFP, and Enel Green Power setting a record-breaking low price of $17.70/MWh in Mexico’s most recent renewable energy auction.

What’s Next?

The GOA and the AESO will reflect on the results and success of REP 1 as they move forward with the design of future rounds.  With these Canadian record-setting contract prices, any proposed changes to REP will need to be weighed against the potential for putting upward pressure on future contract prices.  That said, the AESO has been clear that the Indexed-REC approach would be used for REP 1, leaving it open for discussion in future rounds.

As more renewable generation is procured, the AESO will need to consider broader system impacts.  The REP 1 wind generation projects will be built with no new transmission requirements.  The AESO had previously stated that the existing as-built transmission system can accommodate approximately 2,600 MW of new renewable generation.  However, all the REP 1 projects are located in southern Alberta; incremental generation proposed in this region may give rise to congestion issues in future rounds.  Inevitably, the AESO will likely need to consider new transmission investments to achieve the 5,000 MW renewable generation target.

As the industry analyzes the results and contract awards from REP 1, we should anticipate that the AESO may move quickly to launch the next procurement rounds.  For this reason, Power Advisory encourages interested proponents to use this time to prepare by considering the needs or interests for proposed changes to the REP procurement process.  For example, should the REP consider mechanisms to promote regional diversity?  A benchmarked-approach to provide benefit to solar resources?  How might future rounds consider Aboriginal support?  These questions should be considered in context of the success of this first round to deliver low contract prices.

A PDF version of this analysis is available here.