Category Archives: Market Assessment

Lessons for the Clean Energy Transition from CAISO’s Root Cause Analysis Report of the Summer 2020 Heat Storm

Nathan Lev

January 15, 2021

On August 14 and 15, 2020, California’s Independent System Operator (CAISO) directed utilities to initiate rotating outages (i.e., load-shedding) due to constrained grid conditions, which resulted in hundreds of thousands of Californians experiencing rolling blackouts. Subsequently, CAISO, California Public Utilities Commission (CPUC), and California Energy Commission (CEC) jointly released the Preliminary Root Cause Analysis: Mid-August 2020 Heat Storm on October 6, 2020 at the request of Governor Newsom. The final report, which was published on January 13, 2021, incorporated additional data into its analysis but supported the same findings and conclusion.[1] Mainly, the report outlines three contributing factors and recommendations for California. The lessons reported are applicable to all jurisdictions undergoing clean energy transitions in the face of shifting climatic conditions.

Climate change-induced extreme weather events result in electricity demand levels that exceed previously observed patterns used for planning.

The heat storm experienced throughout California and the Western US brought record-breaking temperatures, including an event that is forecast to occur only once every 35 years. This was undoubtedly the main driver of increased electricity demand due to air conditioning and other space cooling uses, exacerbated by COVID-19 work-from-home trends. For example, while the CAISO uses a peak demand-plus 15% reserve planning margin as a resource adequacy target, on August 14th, the operational need arising out of the extreme weather was 1.3-2.5% higher than the 15% reserve planning margin, driven by higher load. Further, since California often relies on imports during extreme events and the heat wave was widespread throughout the western region, neighbouring jurisdictions had little capacity to export as they needed the capacity in to serve their own market.

In transitioning to a cleaner resource mix with increased renewable generation, planning targets must focus on resources that can be relied upon to meet demand in any situation.

As mentioned above, CAISO uses a peak demand-plus 15% planning reserve margin to meet resource adequacy requirements. However, the report notes that the rotating outages did not occur during peak demand hours. Rather, they occurred later in the day. This challenges the planning paradigm that if there is enough capacity to support peak demand then there is sufficient capacity to meet demand for all other hours. As jurisdictions continue to transition towards cleaner energy resources, the share of wind and solar resources that cannot operate on a 24/7 basis will continue to increase resulting in shifting operational needs. Indeed, CAISO has identified net peak demand as a critical period throughout the day that is challenging to meet. Net peak demand is defined as peak load net of solar and wind generation, which generally occurs later in the day then peak demand. For example, on August 14th, net peak demand occurred at 6:51pm and was 4,565 MW lower than peak demand, which occurred at 4:56pm. However, over the same hours on August 14th, wind and solar generation had decreased by 5,431 MW. It is evident that as resource mixes continue to change, critical periods will shift throughout hours, seasons, and conditions.

Demand and Net Demand for August 14 and 15, 2020[2]

Market and scheduling practices must not distort supply and system conditions.

CAISO recognized that certain market practices led to an inability to obtain additional energy that could have alleviated strained conditions. Mainly, scheduling coordinators under- scheduled on average 3,500 MW of demand in the Day-Ahead Market, which signalled to internal resources that they could monetize their additional capacity through exports. Additionally, CAISO identified similar results arising out of convergence bidding and the configuration of the residual unit commitment market process.

Lessons for transitioning jurisdictions.

The report provides recommendations for the near-, mid-, and long-term periods. Among them are included adjustment to market practices to address under-scheduling, tracking and ensuring that resources under construction meet their planned operational dates, and expediting processes to support demand-side resources with a focus on flexibility and demand response. Other recommendations can be taken as lessons for other jurisdictions:

  • Resource planning and procurement: System planners and regulators should consider whether their resource adequacy requirements adequately consider for extreme weather conditions and accurately reflect their supply mix’s ability to meet system demand in all conditions.
  • Improving situational awareness and planning for contingencies: Similarly, system operators should develop sufficient protocols with their neighbours and all available internal resources to address contingencies and extreme events in real time.
  • Resource planning and development: As jurisdictions continue to transition to cleaner energy supply mixes, they should consider how the resources operational characteristics and constraints contribute to critical periods and apply this understanding to capacity qualification and other metrics used for planning and market purposes. It is evident that the need for flexible and demand-side resources is emerging.

[1] Final Root Cause Analysis: Mid-August 2020 Heat Storm, prepared by: California Independent System Operator, California Public Utilities Commission, and California Energy Commission, published January 13, 2021:

[2] Final Root Cause Analysis, page 45.

Merchant Energy Storage Coming of Age in North American Power Markets

Nathan Lev, Power Advisory LLC

December 8, 2020

Recent announcements in Texas and Alberta are signalling the coming of age of energy storage – particularly battery energy storage systems (BESS) in North American power markets. This is demonstrated by the increasing amount of large, grid-connected BESS being financed and developed on a merchant basis rather than relying on utility off-take agreements. In Texas, Houston-based Independent Power Producer (IPP) Broad Reach Power has begun construction of two separate 100 MW/100 MWh BESS set to reach commercial operation in 2021: Bat Cave Energy Storage in Mason County and North Fork Energy Storage in Williamson County.[1] In Alberta, WCSB Power – a wholly-owned subsidiary of TD Greystone Infrastructure Fund recently began operating Phase I of the eReserve BESS, consisting of 20 MW of Tesla Megapack batteries. WCSB Power additionally holds the rights to expand the eReserve BESS to up to 60 MW (Phases II and III) through 2021.[2]

These projects demonstrate a shift towards an IPP approach to the development and management of BESS, where a fleet of assets is strategically located and operated to provide arbitrage and ancillary services by actively participating in the wholesale markets. Additionally, these IPPs have indicated a strong interest in contracting with commercial and industrial (C&I) customers to provide “risk management products”. However, what is unique to this burgeoning energy storage business model is that these IPPs can provide a physical hedge that is tied to a portfolio of assets rather than a single facility.

It also makes complete sense, and reinforces the maturity of the energy storage market, that these projects are being pursued in jurisdictions with energy-only markets, particularly the Electric Reliability Council of Texas (ERCOT) and the Alberta Electric System Operator (AESO). This is because these markets allow BESS to maximize revenues based on their two key physical and operational characteristics, which is that they are fast-responding and dispatchable (albeit on an energy-limited basis). This is also what makes BESS unique among all other resource types and prompted the former Federal Energy Regulatory Commission (FERC) Commissioner Cheryl LaFleur to hail energy storage a “game-changer” in Order 841.[3] Consider the following:

  1. First, these markets experience extreme price volatility (e.g., reaching up to $9,000 per MWh USD in ERCOT and $1,000 per MWh CAD in AESO) and ERCOT offers sub-hourly pricing and settlement, which BESS can take advantage of. For this reason, loads such as C&I customers have a lot of value to be gained from hedging through contracts and price volatility offers high revenue potential through energy arbitrage.
  1. Second, a relatively high penetration of variable renewable generation (i.e., wind and solar) in Texas (i.e., approximately 25%) and an increasing amount in Alberta (i.e., nearing 15%), along with nodal pricing in ERCOT creates high value for grid operators for ancillary services, notably frequency regulation (also known as regulation service). Perhaps the best example of this potential revenue was demonstrated in Australia (also an energy-only market), when Tesla’s Hornsdale battery earned over $1 million in revenue over a matter of days by taking advantage of tight grid conditions that caused a frequency regulation sub-product to reach nearly $15,000 per MWh.[4]
  1. Third, the ease of transacting in these markets and the relatively high penetration of wind and solar generation created an environment conducive to corporate sourcing of renewables (also referred to as corporate power purchase agreements). However, given that these resources are intermittent, BESS providers can separately provide firming services for companies procuring renewable energy, that would otherwise need to obtain firming services from a retailer.


[1] “The Race is On to Build the Biggest Batteries in Texas” by Julian Spector, Greentech Media, September 15, 2020:

[2] “TD Greystone Infrastructure Fund Invested in Canada’s Largest Battery Energy Storage System” in NewsWire, October 14, 2020:

[3] “FERC Removes Regulatory Barriers to ‘Game-Changer’ Energy Storage Options” in The Energy Mix, February 18, 2018:

[4] “Tesla’s giant battery in Australia made around $1 million in just a few days” by Fred Lambert, Electrek, January 23, 2018:

EV Charger Industry Sees First Major IPO – ChargePoint

When the electric vehicle charger company ChargePoint went public on September 24, 2020 through a reverse merger, there were a lot of investors celebrating the $2.4 billion valuation (enterprise value) that the company achieved.  The company had backers from the oil & gas, utilities and automotive industries including US firms Chevron and AEP and European firms Daimler, BMW and Siemens.  There was also a wide range of venture capital and private equity investors including GIC and Canada Pension Plan Investment Board.

In a buoyant stock market, the company’s valuation was a lofty 18x its calendar year 2020 expected revenue of $135 million.  And going forward, the company projected some big numbers: they estimated revenue would climb to $2.1 billion by 2026, a 58% CAGR over a seven year period, and gross margin would reach 42% (see Figure 1 and Figure 2).

Figure 1. ChargePoint’s Revenue 2017-2026

Source: ChargePoint Investor Presentation, September 24, 2020

Figure 2. ChargePoint’s Gross Margin 2017-2026

Source: ChargePoint Investor Presentation, September 24, 2020

But despite the hockey stick revenue growth, there is still a long way to go even before the company reaches profitability.  For the Fiscal Year ended January 2020, ChargePoint posted revenue of $147 million, but a loss of $133 million driven by high R&D expenses ($69 million) and sales & marketing expenses ($57 million).  The company expects to become EBITDA positive by FY2025.

As shown in Figure 2, the company’s gross margin declined from 2017 to 2019 before bouncing back in 2020.  Until 2018, ChargePoint focused exclusively on the Level 2 market.  When it came out with a DC fast charger product in 2018, the margin declined owing to one-time charges and initially low manufacturing volumes of the new product, followed by new product introductions in Europe.  But the margins are expected to increase as the business scales.


Along with Tesla and Electrify America, thirteen-year-old ChargePoint is one of the leading players in the charger infrastructure market in the US and Canada.  They also have a presence in 16 European markets.  According to data from the US Department of Energy Alternative Fuels Data Center, ChargePoint operates more chargers than any other company in the US and Canada with about 38,000 Level 2 units and 2,000 DC fast chargers (Figure 3).  Together with Tesla and Electrify America, these three companies currently account for about 80% of all networked Level 2 and DCFC chargers in the US and Canada and 90% of DCFCs, the fastest growing market segment.  EVgo and Greenlots (Shell) are the #4 and #5 DCFC network operators.

Figure 3. Charger Portfolio by Network Provider (Number of Units)


  1. Sorted by number of DCFC chargers
  2. Includes chargers across the US and Canada
  3. Some units may have multiple ports so the number of ports is higher.

Source: US DOE Alternative Fuels Data Center, October 2020

Value Chain and Business Model

Figure 4 shows the EV charger value chain.  For new installations, the value chain includes the hardware (which includes the charger, interconnection switchgear, transformers, panels and breakers), project development, site design and installation.  For the installed base of chargers in the field, the value chain includes charger ownership, the network provider (the company that provides the software that runs the charger and handles billing and reporting) and operations and maintenance.

Figure 4. EV Charger Value Chain

Source: Power Advisory

ChargePoint is primarily a hardware provider and network provider.  They have a charger product line (some of it contract manufactured) that they sell to their customers and then provide software and warranty subscription services to the installed base.  On a revenue basis, about 80% of ChargePoint’s revenue comes from selling charger stations and 20% from software and warranty.  The charger owner (the site host) collects revenue generated from the operation of the charger over the course of its life.  For installation, ChargePoint works with partners that they recommend to their customers, but ChargePoint does not have in-house installation or O&M staff, opting for a “capital light” approach.  They sell a parts and labor warranty called Assure which sits on top of the standard product warranty, both of which are fulfilled by their network of O&M partners.

Key points related to the business strategy of the top 5 network providers are shown in Figure 5.

Figure 5. Summary of the Top 5 DCFC Network Providers

Source: Power Advisory

Charger Manufacturers

Most network providers don’t have their own charger hardware product.  ChargePoint, along with Tesla, Blink and SemaConnect, are the exceptions.   ChargePoint also typically doesn’t adhere to industry communication protocols, instead going with their own proprietary standard.  Tesla is similar in that they are 100% focused on their own proprietary chargers that only talk to Tesla vehicles.  By contrast, other network providers provide services on chargers that have been manufactured by independent companies (see Figure 6 for a list of charger manufacturers around the world).

Figure 6. Charger Manufacturers Around the World (grouped by headquarter location)

Source: Power Advisory

Margins for hardware are comparable to electronic hardware margins in other industries.  We expect that gross margins will be in the 25%-30% range (+/-) though there could be some commoditization over time leading to margin erosion.  Installation gross margins are typically 20% and includes margin on all of the equipment items (i.e., interconnection switchgear, panels, breakers, transformers) except the charger itself.  O&M is a labor intensive business and gross margins in that business are higher than installation gross margins.  But the network provider, which is a software business, can do very well on margins, especially as the business scales, since incremental expenses are small.  That’s where ChargePoint will benefit as the installed base grows.

Fleets – the Growth Market

ChargePoint says that fleets are the fastest growing part of their business, and expects that segment to account for 38% of revenue by 2026 (see Figure 7).

Figure 7. ChargePoint Revenue by Market Segment

Source: ChargePoint Investment Presentation, September 24, 2020

Indeed, the fleet business has been growing steadily. Buses have been the early fleet market, but passenger cars and delivery vans won’t be far behind.  When the total cost of ownership for electric vehicles becomes lower than that of internal combustion engine (ICE) vehicles, fleets will rapidly move over to the new technology, and have begun doing so already.  Europe will likely be earlier due to higher gas prices than North America.

ChargePoint’s product offering for fleets is more expansive than for its residential and commercial businesses (Figure 8).  They provide the hardware solution and several associated subscription services.  Whereas for commercial customers they just provide a networking service, for fleets, they offer to optimize schedules and fueling, and manage the customer’s energy usage.  ChargePoint also provides professional services for design/build and provides parts and labor warranties.  This broader offering will result in a larger revenue stream per unit than for commercial customers.  The reasons why fleet operators opt for these products and services are shown in Figure 9.

Figure 8. ChargePoint’s Fleet Product and Service Offering

Source: ChargePoint Investment Presentation, September 24, 2020

Figure 9. Reasons Why Site Hosts electrify their fleets

Source: ChargePoint Investment Presentation, September 24, 2020

Following a challenging year during Covid in 2020, EV charger growth is expected to pick back up again for both the commercial and fleet businesses in 2021 as EV adoption continues. Many opportunities exist for companies to pursue revenue and margin across the value chain.  That includes new entrants and companies that already play in one part of the value chain, but might be able to leverage their position into other parts of the value chain.  With such a high growth market, there will be many opportunities.  Hardware and installation are the largest opportunities, but the downstream activities of network provider and O&M will grow as the installed base grows.  Other important supporting functions such as project development, site design, and software development will also find their niches.


Andrew Kinross is a Director with Power Advisory.  He can be reached at

PDF: EV charger industry sees first major IPO – ChargePoint

Large Scale Renewables Procurement on New York State’s Path to 70% Renewable Energy by 2030 and 100% Carbon-Free Electricity by 2040

While the announcement of combined solicitations for 4,000 MW of offshore wind (NYSERDA) and land based renewables (NYSERDA & NYPA) on July 21, 2020 was historic, this is the continuation of a ramp up in renewables procurement in New York State and indicative of what is required for the state to meet its goals established in the Climate Leadership and Community Protection Act.[1] In the last three years, 2017-2019, NYSERDA has contracted about 6,000 MW of large scale renewables. The state’s procurement will not stop in 2020. NYS will continue to be an attractive market for clean energy development offering opportunities for long term contracts.

Figure 1: NYSERDA Large Scale Renewables Contract Awards (2013-2019)

Additional contracting opportunities to NYSERDA’s centrally administered solicitations (noted in Figure 1) include procurements by the New York Power Authority, Long Island Power Authority and institutional buyers such as the New York Higher Education LSRE. To contextualize this recent procurement and where the state is heading on its path to achieving 70% renewables by 2030 and 100% carbon-free electricity by 2040, Power Advisory offers the following summary timeline highlighting NYS’s climate and energy policies; solicitations and awards; as well as related clean energy announcements from recent years.

Figure 2: New York State Clean Energy Timeline

At least 25% of the projected 2030 system supply mix has yet to be contracted by NYSERDA. This equates to about 40,000 GWh or 11.5 GW of land-based renewables and 4.1 GW of offshore wind to be contracted.[1] These requirements could be even greater if there is higher than expected load growth with strategic electrification (estimates based on NYSERDA’s 2030 load estimate of 151,678 GWh), attrition of contracted projects, and retirement of baseline and off-contract resources (which produce about 39,000 GWh annually).

Figure 3: New York’s Projected 2030 Generation Mix

A PDF version of this note is available here.

Carson Robers, Senior Consultant; John Dalton, President; and Ami Khalsa, Consultant

[1] NY DPS and NYSERDA, “CES White Paper Technical Conference Presentation,” July 14, 2020{526E9A5B-9ED8-4E39-A404-C4BD42F9F9EE}

[1] NYSERDA, “Governor Cuomo Announces Largest Combined Solicitations for Renewable Energy Ever Issued in the Combat Climate Change,” July 21, 2020

Recent New York White Paper Proposes Addition of Tier 4 (Renewable Energy Deliveries into New York City) to the Clean Energy Standard

July 10, 2020

Last month the New York State Energy Research and Development Authority (NYSERDA) and New York Department of Public Service (DPS) published a White Paper on Clean Energy Standard Procurements to Implement New York’s Climate Leadership and Community Protection Act. This White Paper aims to provide a framework to better align the state’s Clean Energy Standard (CES) with its Climate Leadership and Community Protection Act (CLCPA) passed in 2019 while also utilizing the existing CES procurement structure to achieve the state’s target of 70% renewable energy by 2030. In part, within this White Paper NYSERDA and the DPS staff propose the addition of a Tier 4 to the CES in order to promote greater renewable energy delivery into New York City (NYISO Zone J).[1]

In 2019, New York City alone represented 33% of state electricity consumption. Whereas the Tier 1 and predecessor Main Tier Program has resulted in the development of renewable energy largely in the upstate region. The new Tier 4 Program focuses on bringing more renewable energy downstate, specifically to New York City. The proposed program would provide financial support for renewable energy transmitted into Zone J and create a procurement structure distinct from the procurement for offshore wind which will also interconnect downstate.

As proposed, any renewable energy system will be eligible under the Tier 4 Program, as long as it has a commercial operation date (COD) on or after the publication date of any New York Public Service Commission order authorizing this new tier. The White Paper outlays the delivery requirement as the renewable project must either be located in Zone J or involve a new transmission connection to deliver renewable energy to Zone J. Tier 4 RECs would also be eligible to meet compliance standards set by New York City Local Law 97, which aims to reduce building emissions but allows RECs delivered to the city to serve as an alternative form of compliance.

Importantly, the eligible resources are proposed to include the full complement of renewable resources including large scale hydropower. In this way the procurement is expected to have a number of similarities to the Massachusetts 83D renewable energy procurement that resulted in the selection of the 1,200 MW New England Clean Energy Connect (NECEC) to import hydropower from Hydro-Québec.  Similarly, given that CES Tier 4 resources will have to be delivered to New York City this proposal is likely to support the development of new transmission.

However, there are some key differences that are likely to result in greater opportunities for non-hydroelectric renewable energy resources from upstate New York and/or Canada. In the White Paper, NYSERDA seeks the ability to procure RECs from hydropower that does not involve new impoundments and is additional to the baseline production of energy from the supplier. Effectively these constraints are likely to limit the Tier 4 opportunity to hydro units that are already under construction or hydro energy that was previously spilled and also seeks to prevent hydroelectric energy from being diverted from other markets.

The White Paper recommends a procurement target for Tier 4 resources of up to 3,000 MW and suggests using the same solicitation and contracting process as used for Tier 1 resources. This process would include negotiating the COD on an ad hoc basis as well as allowing NYSERDA to enter into contracts with a tenor of up to 30 years and with multiple entities as necessary. The White Paper also proposes enabling NYSERDA to solicit both Fixed and Indexed REC bids under Tier 4 with a price cap. This price cap aims to ensure that renewable penetration into New York City increases without undue ratepayer impacts. Similar to Tier 1, compliance with the Tier 4 would be the financial responsibility of all load serving entities (LSEs) but the program would be centrally administered by NYSERDA.

Next Steps

With the publishing of the White Paper in docket 15-01168/15-E-0302, a 60-day public review and comment period was initiated. After which the Commission will act on the proposals in the White Paper and issue any orders determining the program design and implementation.

[1] The White Paper’s other proposals are not reviewed within this Power Advisory client note.

John Dalton, President; Carson Robers, Senior Consultant; and Sophia Vitello, Research Analyst

A PDF version is available here Power Advisory_New York Tier 4 Client Note_2020-7-10.

New England Class I REC Market Update

While most Class I REC markets across the country are generally oversupplied, the smaller New England Class I REC market stands apart as recent events have driven prices dramatically higher over the last year (Figure 1). In fact, 2019 vintage Class I RECs have climbed all the way from $7/REC a year ago to about $40/REC today, a stunning 5.7x increase. This suggests a shortage of RECs available in the marketplace to compliance entities who need to meet state Renewable Portfolio/Energy Standards.

Figure 1. 2019 Vintage ISO-NE Class I REC Prices, Last 12 Months ($/REC)

Source: S&P Global, Power Advisory analysis

The main factor influencing the REC market is the anticipated timing of completion of a series of large offshore wind projects. There are currently 2,304 MW under contract in New England (including the 804 MW Mayflower Wind project which is negotiating PPAs with the Massachusetts electric distribution companies) and more expected in the future (namely an ongoing Connecticut procurement process for up to 2,000 MW). While the 800 MW Vineyard Wind project owned by Avangrid Renewables and Copenhagen Infrastructure Partners had appeared construction-ready, and almost at financial close, it suffered a setback when the Bureau of Ocean Energy Management (BOEM) delayed the project’s federal permitting on August 9, 2019. BOEM has mandated that Vineyard Wind to go through a supplemental draft Environmental Impact Statement (EIS) process that takes account the cumulative impacts of offshore wind development in the region.The timing of this analysis is unclear and is subject to normal public comment and review. Vineyard Wind is expected to be delayed at least six months, with potential knock-on effects for the rest of the offshore wind pipeline.

Other significant events that have driven prices higher by increasing REC demand or reducing supply include:

  • Maine increasing its RPS in June 2019 following the election of a new clean energy-friendly governor last year, and
  • National Grid selecting only one significantly smaller solar project for negotiation from its 400 MW renewable RFP in Rhode Island.

But it’s the offshore wind that is the big driver. Assuming a 48% capacity factor, the three ISO-NE utility-scale offshore wind farms alone that are under contract, consisting of Vineyard Wind (800 MW), Revolution Wind (700 MW) (Orsted/Eversource) and Mayflower Wind (804 MW) (Shell/EDPR), would generate almost 10 million MWhs when they are connected to the grid. Should those projects be connected by 2030 as expected, the modest amount of onshore renewables recently contracted come online, and trends in behind-the-meter solar continue, a gap of about 11 million MWhs would remain to meet RPS requirements within New England as a whole. However, Connecticut’s targeted 2,000 MW procurement and an additional 1,600 MW of offshore wind planned by the Massachusetts Department of Energy Resources will fill – and then exceed – the estimated gap.

When considering the balance of the REC market it is important to note that each state has its own renewables standards and procurement statutes, with respective definitions, eligibility requirements and targets (see Figure 2 for the current Class I equivalent standards). Furthermore, RECs are tradable within ISO-NE and from adjacent control areas.

Figure 2. Current New England Class I Standards Through 2050

Once the contracted offshore wind projects reach commercial operation, expected to be in the 2023-2026 time frame, Class I REC pricing will presumably stabilize and then begin eroding as the much needed RECs hit the market. Until then, the pricing could remain high, as the market appears to be undersupplied. The additional 3,600 MW of offshore wind expected to be contracted by Connecticut and Massachusetts will result in an oversupplied market starting in the late 2020s.

Alternative Compliance Payment (ACP)

The alternative compliance payment (ACP) acts as ceiling to the market. The ACP is $70.44/REC in Massachusetts for 2019 and $55.00/REC in Connecticut. Thus, current bid-asks as lofty as $46/REC according to the Intercontinental Exchange, or 84% of the CT ACP, signal that we are nearing or at an undersupplied market. That’s because the alternative is to pay the ACP which is not that much higher.

New Build Capacity to Meet 2030 Targets

As noted above, Power Advisory estimates that the incremental 3,600 MW of offshore wind expected from Connecticut and Massachusetts in addition to the current renewables contracts and supply would entirely satisfy the 2030 New England RPS requirements. The aggressive offshore wind procurement targets combined with high capacity factors squeeze out opportunities for onshore wind and solar assets that have been used to comply with RPS to date. This is not to say that there are not onshore renewables development opportunities. For example, Maine will be issuing two near term Requests for Proposals for the equivalent of 14% of its 2018 retail electricity sales (discussed in Power Advisory’s July note on recently enacted legislation in the state).

Expected Long Term REC Pricing

Following the current New England Class I REC price spike, we expect prices to stabilize and then erode as the project development process catches up with the mandates, driven mainly by offshore wind and to a lesser extent, the Massachusetts SMART program and other procurements. Longer term (post-2030), we expect an oversupply of RECs leading to a substantially lower REC prices. Projects will become less reliant on RECs over time. Future regulatory and policy announcements, load growth due to electrification, or substantial retirements could support higher prices.

A PDF version of this note is available here.

Power Advisory welcomes the opportunity to assist clients’ understanding of the New England REC market and assessment of renewables development in the region.

US OSW Project Construction Pinch Points

Two weeks ago New York State announced that they were negotiating contracts with two OSW projects totaling 1,696 MW, with 2024 commercial operation dates (COD), a year when additional 1,348 MW is scheduled to enter commercial operation: Ørsted US Offshore Wind’s (Ørsted’s) 1,100 MW Ocean Wind Project and US Wind’s 248 MW Maryland project. With this the US Northeast/Mid-Atlantic has awarded or is anticipated to award this year OSW contracts representing over 6,000 MW. These are shown by their anticipated COD and developer below.

* Ørsted projects are with various partners including Eversource, PSEG and Dominion.

These projects will result in cumulative investment of about $22 billion and about 13,000 direct jobs (FTEs) and a total employment impact of over 42,000 during the construction period. This is a quick start to a major new industry where the supply chain to support it is just beginning to be developed. An obvious question is: can this industry develop at this pace, without significant and costly growing pains? While there are many challenges, work appears to be underway to address some of the largest pinch points. Oft-cited examples include ports, vessels and qualified labor in some trades (ex. metal fabrication and marine services).

States and OSW developers are aware of the port constraints and are seeking to ensure that the necessary investments have been made to enable the construction of these projects at reasonable costs and without undue delays.  Based on our assessment some gaps are that Vineyard Wind appears to need an additional port for its 800 MW contract with the Massachusetts EDCs beyond the New Bedford Marine Commerce Terminal and Equinor is in need of a port for marshalling, but New York State has earmarked $200 million for near term port development. 

Sufficient suitable vessels are another possible constraint. The Jones Act and port infrastructure clearly will shape the vessel spreads that developers will employ. While there are reportedly Jones Act compliant OSW installation vessels under construction, vessels and port restrictions including their size (both laydown area and quayside length), air draft restrictions and available infrastructure present challenges.

With respect to labor force constraints, this level of OSW development would result in about 2,400 fabricated structural metal manufacturing jobs and 1,600 marine services jobs (FTEs) during the construction period and over 500 OSW maintenance jobs. These are three areas with particular needs that could outstrip available resources, without training.  However, numerous investments being made by states and OSW developers to develop the workforce and suggests that this potential constraint is beginning to be addressed.

Some final questions:

  • Our initial analysis indicates that the critical pinch points are being addressed.   However, how do all these programs and investment fit together?
  • Is there unnecessary overlap or areas where additional investment will provide the greatest benefit in terms of avoiding supply constraints and facilitating the desired development of the OSW supply chain in the US?

New York Market Forecast and Renewables Development Consulting Services

Have you submitted an Application for Qualification for a generation project in the ongoing NYSERDA Renewable Energy Standard RFP (RESRFP19-1) or are otherwise looking to advance your renewable project development efforts in New York?

Power Advisory offers a full suite of New York market forecasts and strategy consulting services to support these development efforts. Our services include the essentials to forecast project revenues, understand the major risks and opportunities associated with participating in the New York markets and submitting competitive proposals. Power Advisory’s New York market offerings include:

Electricity Price Forecast (considering zonal and technology weighted NYISO energy revenues)
Capacity Price Forecast (focused on the NYISO spot auctions and locational differences)
NYSERDA Tier 1 REC Forecast (by contract year for the anticipated schedule of RES RFPs)
Carbon Pricing Proposal Analysis (considering the implementation of carbon pricing in the NYISO energy markets)
Policy & Market Backgrounders (covering the key policies and market structures that shape NY generation development)
Proposal Drafting/Strategy (direct support of bid preparation and strategies to maximize your chances for contract award)
Registration/Participation Support (for NYGATS and the NYISO administered markets)

We supported successful proponents in the last NYSERDA solicitation, RESRFP18-1, resulting in executed long-term fixed price REC contracts for our clients. 19 projects totaling 1,364 MW of solar, wind and energy storage were contracted in the 2018 solicitation. The weighted average REC price was $18.52. Since then, New York has upped its renewable and clean energy commitments with targets of 70% renewables by 2030 and 100% carbon-free electricity by 2040 and there have been other significant market changes.

Power Advisory specializes in electricity market analysis and strategy, power procurement, policy development, regulatory and litigation support, market design and project feasibility assessment. Our team has completed work in each of the North American electricity markets including numerous consulting projects in New York State. Power Advisory’s understanding of wholesale electricity markets, energy policy, resource procurement and renewable technologies makes us well qualified to support your generation development efforts.

Recently Enacted Legislation Opens Up New Renewable Generation Development Opportunities in Maine

Since Janet Mills was sworn in as governor in January and the democrats had also secured control of both chambers, the expectation was that 2019 was going to be a big year for climate and clean energy in Maine. This has certainly turned out to be true. As an early action, Governor Mills issued Executive Order 3 FY 19/20 to conclude the Maine Wind Advisory Commission and wind permit moratorium that had been in place since the beginning of 2018. A flurry of legislation was also introduced addressing everything from net metering (re-instituted in March through L.D. 91) to electrification, the renewable portfolio standard, procurement targets and Aqua Ventus floating offshore wind pilot project.

Leading up to the adjournment of the legislative session on June 20th a number of these bills passed and were subsequently signed by the Governor. Most notable to renewable generation development in the state were L.D. 1494 and L.D. 1711, which are reviewed below. These offer direct opportunities for long-term contracts for new projects. Respectively, about 400-800 MW of utility scale renewables and 375 MW of distributed solar by 2024.

An Act To Reform Maine’s Renewable Portfolio Standard (L.D. 1494 / Chapter 477 PL)

L.D. 1494 passed the legislature on June 18th, 2019 and was signed into law by the Governor the following week. It expands Maine’s RPS to 80% by 2030 and to 100% by 2050 from 40% (Class I – New 10% and Class II – Existing Resources 30%) while creating a new class of RPS resources, Class IA, for the incremental renewable generation capacity targeted.

In addition, it calls for the competitive procurement of Class IA resources to the level of 14% of 2018 state retail electricity sales, about 1,500 GWh, through a series of two RFPs to be issued by 2021. Energy storage, mechanical, chemical or thermal, can be awarded contracts if paired with eligible Class IA resources. The first RFP is likely to be issued in late 2019 or early 2020 for approximately 750-1,100 GWh (7-10% of 2018 sales per the legislation). A second RFP will then be issued in late 2020 but no later than Jan 15th, 2021 for 450-750 GWh (14% of 2018 electricity sales minus the generation contracted in the first RFP).

The Maine Public Utilities Commission is responsible for administering the reformed RPS  including the two mandated procurements. In this role, the Commission is to direct the Maine investor-owned transmission and distribution utilities to enter the long-term contracts selected from the RFPs. The state’s two investor owned utilities are Avangrid’s Central Maine Power (CMP) and Emera Maine (Bangor Hydro Electric Co. and Maine Public Service Co.), which is pending sale to ENMAX Corporation. While the Commission will retain significant discretion in the solicitations certain aspects were directed in L.D. 1494.

Overall the estimated near term opportunity resulting from the reformed Maine RPS is 400 MW of  land based wind, 850 MW solar or a combination of the two technologies.This opportunity for new renewable generation resources could be up to 25% lower to the extent that sufficient resources that began commercial operations on or prior to June 30, 2019 are available.

An Act To Promote Solar Energy Projects and Distributed Generation Resources in Maine (L.D. 1711 / Chapter 478 PL)

L.D. 1711 calls for the competitive procurement of distributed generation (DG) resources in sequential blocks for a total of 125 MW commercial or institutional DG (i.e. non-residential customers) and 250 MW of community shared DG by July 1, 2024. The initial procurement must occur on or before July 1, 2020 with the rules for both solicitations to be in place by January. Four additional blocks of DG are then to be used by the PUC to meet the overall procurement goals with stipulations on each block that the contract rate be equal to 97% of the preceding block. For the purposes of these procurements a DG resource means an electric generating facility with a nameplate capacity less than 5 MW that uses an eligible renewable fuel or technology and is located in the service territory of a Maine T&D utility. Solar is understood to be the predominant distributed renewable technology.

There are number of specifics in this law with regards to the competitive procurements and net energy billing which should be reviewed. An earlier version included a 400 MW utility-scale procurement provision with a $35/MWh cap, but that was struck from the enacted version.

Carson Robers, Senior Consultant, Power Advisory LLC

A PDF version of this note is available here.

Review of New Jersey Ocean Wind Project Pricing

This memo updates our review of the New Jersey Board of Public Utilities (BPU) Offshore Wind Renewable Energy Certificates (OREC) award to Ørsted US Offshore Wind’s 1,100 MW Ocean Wind project. The BPU made available its order and this provided additional details, which required that our earlier memo be updated. In this memo, we focus on the Ocean Wind contract pricing.

The Ocean Wind project will be developed in three tranches of 368 MW each with a COD in 2024. The first year all-in OREC price is $98.10 per MWh and this price is realized only by Phase 1 for one-month after which it escalates. The price escalates at 2% per year such that in 2045 the contract price will be $148.68/MWh. This equates to a nominal levelized price of $116.82/MWh, representing a 19% premium relative to the price for the smaller Revolution Wind project secured by Rhode Island, which has a similar COD in 2024. The premium is considerably greater relative to the contract price for the Vineyard Wind project, which is able to realize a higher investment tax credit.

Nominal Levelized Pricing Comparison ($/MWh)

Frankly, we are surprised by the magnitude of this premium, even with the superior wind resource that is available to the Revolution Wind project. Interestingly, the OREC Order provides for an annual OREC allowance, which implies a 50%, capacity factor which is higher than that reported for Revolution Wind. However, Ocean Wind is precluded from selling more ORECs than its annual allowance, so this allowance is likely to be greater than a P50 estimate.

The lack of transparency regarding the evaluation and scoring framework used by the BPU doesn’t help in explaining this outcome. The BPU evaluation criteria were identified as the OREC purchase price, economic impact, ratepayer impact, environmental impact, the strength of guarantees for economic impact, and the likelihood of successful commercial operation. However, the relative weights of these evaluation criteria aren’t specified and the tradeoffs that the BPU made in selecting Ocean Wind cannot be ascertained.

Nonetheless, it does appear that there were tradeoffs with respect to these evaluation criteria. Specifically, the BPU order indicates that the Ocean Wind project “provides the best economic development benefits to the state of any of the applicants.” Further, it notes that “Although other projects presented a lower PVNOC [Present Value of Net OREC Cost], given the Ocean Wind 1,100 MW project’s strength in all of the other evaluation criteria, an award to Ocean Wind is in the best interest of the State of New Jersey and its ratepayers” (BPU Order, p. 19).

A PDF version of this memo is available here.