Category Archives: Market Assessment

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.

Summary and Commentary on the Energy Storage Advisory Group 2019 Work Plan

(Preview of Document)

Date: May 31, 2019
For parties interested in: Energy Storage and Innovation in Ontario


  • The Independent Electricity System Operator (IESO) released “Removing Obstacles for Storage Sources in Ontario” report on December 19, 2018 based on consultation with its Energy Storage Advisory Group (ESAG).
  • On May 24, 2019, the IESO presented the 2019 work plan to the ESAG for addressing barriers to energy storage resources in the IESO-Administered Market (IAM).
  • The 2019 work plan includes two committed projects and four prospective projects.

See the full post in the link below.

PDF: Power Advisory -ESAG Commentary -May 2019

IESO 2019 Planning Outlook – Resource Adequacy Outlook Summary and Commentary


  • The Independent Electricity System Operator (IESO) has enacted a new annual planning outlook, building on the 2018 Technical Planning Conference (TPC) held in September 2018[1].
  • The IESO hosted a stakeholder engagement on April 12th, 2019, on their resource adequacy outlook and to outline their approach to assessing supply need and available resources.
  • The resource adequacy outlook is a major component of the annual planning outlook the IESO intends to publish in Q3 2019; the annual planning outlook determines supply adequacy needs which will be used to inform Target Capacities for the Transitional Capacity Auctions (TCAs) and Incremental Capacity Auctions (ICAs).


In September 2018, the IESO hosted a TPC to present a new planning approach.  The 2018 TPC presentation clearly indicated a resource adequacy gap starting in 2023.  The IESO Market Renewal Program[2] (MRP) seeks to implement fundamental reforms to the IESO-Administered Market (IAM).  One objective of MRP is to promote more market-based mechanisms to procure required resources to meet system need.  As such, the IESO planning process is evolving to support this new framework with the introduction of an Annual Planning Outlook (APO).  On April 12th, 2019, the IESO hosted a stakeholder engagement session to discuss the resource adequacy outlook framework and to update stakeholders on the demand outlook.  The demand outlook and resource adequacy outlook are the two major components of the APO.

The IESO reviewed stakeholder feedback from the January 31st, 2019, engagement sessions and presented on three areas of resource adequacy:

  • Process overview;
  • Capacity Adequacy Assessments; and
  • Energy and Operability.

This client note will review each of the areas covered by the IESO and provide our commentary after each section.


The January 31st, 2019, APO stakeholder engagement session was focused on Ontario’s evolving planning process, preliminary demand outlook and the updated reliability outlook[3].  Feedback from stakeholders to the session was robust with over 120 comments and questions submitted to the IESO.  In the IESO’s view, feedback can be organized into three broad categories: methodology of demand and resource adequacy; reporting and economic analysis; and data transparency.  Partially due to the feedback received in addition to continued analysis, the IESO made the following adjustments to the demand outlook:

  • The IESO will use the most recent year (2018) as the base year;
  • Past conservation savings are included in gross demand forecast, future conservation savings will not include past savings;
  • Electric vehicle and public transit forecasts will consider the most recent Federal Budget released in March 2019;
  • Natural gas price forecast will be updated; and
  • Conservation assumptions updated to reflect the March 21st, 2019, Ministerial Directive[4].

Robust feedback from stakeholders demonstrates the importance and value of the IESO’s decision to adopt an annual planning process.  The electricity sector in general is undergoing significant change and uncertainty.  An annual planning process provides both stakeholders and the IESO a consistent opportunity to discuss issues and their impact on system needs.  To that end, the IESO should be commended on their response to feedback received from stakeholders which demonstrates that the IESO is attempting to incorporate information to enhance system need analysis.

The APO conclusions will be used to inform Target Capacities in the TCAs and ICAs; therefore, it is important that all stakeholders have a firm understanding and general agreement with the IESO’s planning process.  Without transparency and openness in the IESO planning process, investors will have reduced confidence in the Ontario electricity market which could increase costs for Ontario rate-payers.

One area that Power Advisory firmly believes the IESO could improve upon is sharing of data and analysis as part of the APO process.  The IESO continues to limit the sharing of information, especially in preliminary form (e.g., preliminary net and grid demand outlooks).  Preliminary information is important for stakeholders to review and analyze so that their feedback is informed and provided within enough lead time for the IESO to incorporate into the final APO.  A common response from the IESO on requests for more availability of data is confidentiality and security concerns.  Power Advisory recommends that the IESO consider Critical Energy/Electric Infrastructure Information (CEII) procedures in other jurisdictions.  CEII procedures can ensure a person accessing the information is known to the IESO and meets specific requirements for access.

Discontinuing the CFF and IAP will have a significant impact on Ontario’s electricity sector.  For the IESO, implementing the new directive comes at a time when the organization is already stretched to implement their MRP.  In addition, the IESO is moving to meet capacity needs emerging as early as 2020.  The reduction in new energy conservation will need to be taken into account as the IESO identifies the Target Capacities for both TCAs and ICAs.

Clients should note that the IESO has stated that the APO is expected to meet their obligations to the Minister of Energy for a technical report pursuant to Section 25.29 (3) of the Electricity Act, 1998 on the adequacy and reliability of Ontario’s electricity resources.  In other words, the APO is a substitute for the Ontario Planning Outlook that was published in 2016 and used as an input into the 2017 Long-Term Energy Plan (LTEP).


The IESO provided an overview of the resource adequacy outlook process and how the process coordinates with other Ontario electricity planning process.  The objective of resource adequacy is to assess the ability of electricity resources to meet electricity demand, taking into consideration the demand forecast, supply availability and transmission constraints.  In short, resource adequacy is a key component of power system analysis that underpin reliability and other assessments (the other key component is the demand outlook).

Resource adequacy is part of the APO and is related to the IESO’s Bulk Planning Process development that is ongoing.  The IESO intends to publish the 2019 APO in September of this year and will finalize the bulk planning process in Q3-Q4 2019 (see timeline figure below).


Figure 1: IESO Planning Process Timeline

Generally, resource adequacy is applied to three different areas of power system planning: capacity, energy and operability (e.g., ancillary services).  The figure below provides a graphical representation of each of the three areas. For clarity, regulation is an example of an electricity service required for power system operability.

Figure 2: Graphical Representation of Power System Planning Areas

Resource adequacy assessments are completed as part of multiple planning activities (i.e., operational planning, investment planning, and compliance reporting).  For operational planning, resource adequacy is assessed from an outage management viewpoint as part of the 18-month and 60-month Reliability Outlook reports.  For investment planning, the APO identifies supply adequacy needs over a 20-year time horizon to inform investment decisions.  Finally, the IESO has compliance reporting requirements on resource adequacy to the North American Electric Reliability Corporation (NERC) and Northeast Power Coordinating Council (NPCC), see figures below for further details.

Figure 3: Planning Activities for Resource Adequacy Assessments

Figure 4: Comparison of Planning Publications by IESO

In addition, resource adequacy assessments inform and support a number of IESO activities including:

  • Bulk and regional planning processes
  • Outage assessment and approval process
  • Capacity export decisions
  • TCA and ICA Target Capacities

Clearly resource adequacy assessments are an important planning process that influences many different areas of Ontario’s electricity system.  In Power Advisory’s view, there are two key impacts resource adequacy will influence in the near-term.

First, resource adequacy will be used to inform Target Capacities for TCAs.  At the TCA draft Phase I design stakeholder engagement session on April 18th, 2019 the proposed summer target capacity ranged from 811 MW in 2020 to 4,686 MW in 20245.  Those values are subject to APO updates that will be heavily influenced by the resource adequacy assessments.  Adjustments to target capacity can change the opportunities available to clients.  In addition, from 2020 to 2023 the IESO considers a reliability assurance period where they may set target capacities above total resource requirements to create the appropriate business environment and auction process confidence to sustain and develop resources.

Second, different IESO planning activities related to resource adequacy can have different objectives.  The conclusions in the planning reports may not appear to align if the differences in objectives and processes are not well understood.  For example, resource adequacy in the Reliability Outlook report is focused on outage management over the next 18 to 60 months, while the APO is focused on total resource requirement over a 20 year forecast period.  Clients should take time to understand each planning process and how the conclusions will impact their business and assets.



Capacity adequacy assessments determine if there is a heightened risk of using emergency operating procedures or disconnecting firm load due to resource deficiencies.  Adequacy standards define which sources of risk to consider and what level of risk the electricity system should be planned to meet.  Adequacy standards include applicable NERC and NPCC standards as well as the Ontario Resource and Transmission Assessment Criteria (ORTAC)[6].  The primary reliability index used in resource adequacy assessments is Loss of Load Expectation (LOLE).  LOLE is defined as the expected number of days per year for which generation capacity is insufficient to serve demand.  NPCC standard requires the IESO controlled grid to have a LOLE of no more than 0.1 days/year[7]The IESO expects capacity adequacy need to be the main driver for resource investment over the next decade in Ontario.

The IESO’s resource adequacy assessment process is derived from three key inputs: supply outlook, demand forecast, and transmission limits.  Probabilistic analysis is used to determine capacity surplus or deficit based on a range of uncertainties for each assumption.  The probabilistic analysis is carried out by a software tool called the Multi-Area Reliability Simulation Software (MARS).  See diagram of resource adequacy process below.

Figure 5: Resource Adequacy Assessment Process

The supply outlook is determined based on three broad data inputs: supply inventory, performance data, and outage data.  Supply inventory is determined by information drawn from market participants (e.g., market registration data), contracted resources, rate regulated resources and other supply/data sources. Performance data of generator units is derived from seasonal performance conditions.  For example, capacity availability for thermal resources (i.e., gas-fired generation) reflects the impact of ambient conditions.  Thermal resources tend to be less efficient in the summer and more efficient in the winter.  For renewable generation units, energy and capacity limitations are determined by vendor-supplied simulation of hourly profiles that is validated by historical production data in Ontario.  Outage data includes planned outages (e.g., maintenance outages), refurbishment outages (i.e., nuclear), and forced outages.  Forced outages can come in two primary forms.  First, a forced outage where the entire generation unit is unavailable for an unplanned reason (e.g., generation unit stops production for safety reason).  Second, a forced de-rate when less total capacity is available for an unplanned basis.  Forced outages do not need to be directly related to each generation unit, but can include outages in the local power system that force units offline or de-rate the units for a period of time.

To ensure alignment with the MRP, the IESO terminology for capacity is standardizing on the following terms:

  • Nameplate: Resource’s full load, sustained output capability as provided by the manufacturer
  • ICAP: Maximum output capacity of a resource as assessed by the IESO, or demonstrated by physical tests, for conditions expected at times of peak demand need during each season
  • UCAP: Performance adjustment from ICAP of resource for each season (e.g., forecast outages, fuel availability, etc.) including deliverability de-rates due to transmission deliverability

The demand forecast input into MARS is a 20-year period, hourly demand forecast broken down by the IESO zones (i.e., the 10 IESO zones).  The demand forecast is a net demand forecast (i.e., gross demand less conservation activities).[8]  Both demand response resources and embedded generation (i.e., directly connected to Ontario’s distribution systems) are treated as supply side resources, that is similar to generation.  Contributions from the Industrial Conservation Initiative (ICI) and embedded generation located behind-the-meter are treated as load reductions within in the net demand profile.  The demand forecast uses a single set of weather conditions.

Transmission limits impact the ability of generation units located around the province to contribute to supply adequacy needs.  Excess generation in one zone must have enough transmission capability to transfer output to load centers in the province (i.e., deliverability).  For example, transmission limits can restrict the value of capacity additions in zones that do not transfer capability to deliver energy production to other zones that require capacity.  This deliverability constraint impacts LOLE.

The MARS program undertakes a probabilistic analysis of all the inputs to determine the total resource requirement to meet planning standards.  For example, while the net demand forecast uses a single set of weather conditions, load forecast uncertainty is determined based on different probabilities of weather.  The IESO simulates demand many times using the last 31 years of weather data.  Similar variability of inputs related to fuel availability and equipment availability is used in the MARS program. The result of the MARS resource adequacy assessment is total resource requirement over the forecast period (see figure below from 2018 TPC).  Clients should note that the nuclear refurbishment schedule has a significant impact on the total reserve requirement over the forecast period.  At times, the higher uncertainty from the refurbishment program increases the total reserve requirement by over 1,000 MW (light blue area is additional reserve requirement for refurbishment risk).

Figure 6: Total Resource Requirement and Nuclear Refurbishment Schedule Impact

Clearly, the nuclear refurbishment schedule is the primary risk for supply adequacy in Ontario over the next 20 years.  Other key uncertainties impacting the resource adequacy outlook in the IESO’s opinion are detailed in the table below.

Figure 7: Resource Adequacy Outlook Uncertainties

The IESO did not present any updates to the resource adequacy outlook at the stakeholder engagement session.  Therefore, the most recent capacity adequacy outlook for Ontario is the results of the 2018 TPC (see figure below).  Ontario is forecasted to continue to be a summer peaking jurisdiction.  Capacity deficits (not including existing generation with expired contracts) begin in 2020 and grow significantly after 2022.  Even including the capacity of existing generation with expired contracts, Ontario requires new supply in 2023 of roughly 1,400.


Building on the information delivered at the 2018 TPC, the IESO have provided a considerable amount of detail on the resource adequacy outlook and the capacity adequacy assessment process.  As the IESO moves towards adopting ICAs, transparency is required to ensure investor confidence.  While no update to total resource requirement was presented by the IESO, they should be commended for the effort in presenting the technical analysis underpinning their planning process.

The standard terminology for capacity is important for clients to understand.  This is particularly true for how the IESO applies those terms for defining system need and the capabilities of a client’s existing or proposed asset.

At a high-level, Power Advisory agrees with the approach the IESO has presented and the existing total resource requirement.  However, there are numerous areas where technical assumptions and details are debatable.  Adjustments or disagreements can impact the future capacity need and therefore opportunity for clients.  For example, the approach to Demand Response (DR) resources is simplistic and not assessed with the same rigour as other resources such as hydroelectric and thermal resources.

Using 31 years of historical weather data for load forecast uncertainty is abnormal compared to other jurisdictions.  Shorter time periods, for example 10 to 20 years, is more common and better captures rising temperatures due to climate change.

Finally, it merits repeating that the IESO is of the view that capacity need will be the primary driver for new investment in Ontario over the next decade.

Figure 8: Capacity Adequacy Outlook from 2018 TPC


Energy and operability assessments provide insight on the following parameters (see table below).  The IESO uses an hourly energy dispatch model to simulate energy production and economic dispatch of generation resources in Ontario and neighbouring jurisdictions.  The outputs include hourly generation outputs, transmission flows and intertie transactions.  The simulations also incorporate energy, ancillary services and multi-regional dispatch while respecting transmission limits.

Parameter Description
Energy Adequacy and Operability Determines whether or not Ontario has sufficient supply to meet its forecasted energy demands and to identify any potential concerns
Imports and Exports Flows across Ontario’s interties with various interconnected jurisdictions (i.e., New York, Quebec, Michigan, Minnesota, and Manitoba)
Surplus Baseload Generation Periods when electricity production from baseload facilities (e.g., nuclear, hydroelectric, wind, etc) is greater than Ontario’s demand
Transmission Congestion Extent to which resources are bottled due to transmission limits
Dispatch Cost Approximation of the cost of dispatching electricity resources and identifies how system marginal cost change over time
Greenhouse Gas (GHG)  Emissions Amount of GHG emissions from Ontario’s generation fleet

Figure 9: Energy and Operability Parameters

The IESO performs two types of energy assessments.  The first, energy production, assesses the amount of electricity expected to be produced from the generation fleet including trade with neighbouring jurisdictions (i.e., import and exports).  The second, energy adequacy, assesses the self-sufficiency of Ontario to meet internal demand requirements.  In other words, the energy adequacy assessments model Ontario as an isolated system.  The 2018 TPC results expect energy production to decrease from 160 TWh to 150 TWh in the mid-term (i.e., 2020 – 2026) before growing to 170 TWh by 2035.  Ontario’s energy adequacy outlook expects energy production to grow to just under 150 TWh by 2035 from 140 TWh in 2019. Unserved energy, that is the amount of electricity demand that cannot be satisfied by Ontario resources only, is expected to grow to over 20 TWh by 2035.  Unserved energy does not consider any interconnection assistance or continued availability of resources after contract expiration (see figure below).

Figure 10: Unserved Energy

The IESO simulations expect gas-fired generation to increasingly play the role of a swing resource and pick up the balance of energy demand needs when output from other sources are lower or when demand rises.  The IESO expects the combined-cycle gas-fired generation (i.e., CCGT) fleet to increase its capacity factor from <5% in 2019 to almost 50% by 2026.  Depending on continued availability of resources after contract expiration, the capacity factor could grow to over 75% by 2035, or settle at 25% if all existing resources with expired contracts continue to operate.   Surplus baseload generation expectations in the 2018 TPC drops from 10 TWh in 2019 to under 2 TWh annually from 2025 to 2035.

For the operability assessment, the IESO considers the many ancillary service products that the IAM procures in addition to other operational needs (e.g., ramping and load-following capability).  The IESO believes that there is not pressing need for operability and intends to perform a detailed assessment of operability needs (i.e., flexibility & ramping) in 2020 and ancillary services/essential reliability services in 2021.  The current list of ancillary services procured by the IESO is shown below.

Figure 11: IESO Ancillary Service Products

The IESO presented their view of the capability of different resource types to provide ancillary and operability services (see table below).

Figure 12: IESO Assessment of Resource Capabilities for Electricity Services


There are several take-aways from the energy and operability assessment overview presented by the IESO.

First, the carbon intensity of Ontario’s supply mix is expected to rise significant, abet from a low baseline.  Higher capacity factors of CCGT units will increase the amount of GHG emissions from Ontario’s electricity sector, potentially increasing carbon offset benefits for DERs that reduce Ontario’s grid demand and therefore lowers the need for CCGT.

Second, the IESO is forecasting lower SBG in the future.  This is a logical conclusion since Ontario is exiting a period of supply surplus that has persisted over the past decade.  Lower SBG will reduce global curtailment risk for non-hydro renewables in particular.

Third, Ontario has multiple interconnections with neighbouring jurisdictions that can be relied on during a temporary shortfall in unserved energy.  However, relying on imports for too long increases the exposure to activities in other markets that are outside the control of Ontario.  It is also worth noting that Ontario was relying on roughly 4,000 MW of imports during the supply shortfall of 2002 to 2005.  The supply shortfall at the time was a partial reason for the political action to create the Ontario Power Authority and initiate long-term contracts for capacity adequacy resources.  The impact of those decisions 15 years ago still impacts Ontario’s electricity sector today.

Fourth, the IESO’s assessment of different resource types capabilities to deliver electricity services is overly restrictive.  For example, wind and solar generation can offer downward regulation with practically no technological issues (i.e., both resources can reduce their output almost immediately after an outage event if required).  The newly launched Market Development Advisory Group (MDAG) is a forum for the IESO to assess and update resource capabilities for different electricity services.

Finally, clients should note that opportunities in providing ancillary services and operability may not solely come from detailed technical need analysis.  There are multiple stakeholder engagement processes seeking to expand participation and competition of innovative and emerging technologies (e.g., Innovation Roadmap, Energy Storage Advisory Group (ESAG) work plan, etc.).  The stakeholder engagement process may yield investment options and therefore it is important for clients to participate to ensure the opportunities are maximized for their projects or assets.

A PDF version of this report is available here.



[1] More information on the 2018 TPC, including feedback from stakeholders, can be found here:

[2] Overview of MRP can be found here:

[3] The IESO has regularly published an 18-Month Outlook since 2000 to assess the reliability of Ontario’s power system. At the end of 2018, the IESO decided to produce a reliability assessment over a longer 60-month term. The December 2018 is the first 60-month outlook (“the Reliability Outlook”). The IESO intends to publish this 60-month outlook twice a year, in December prior to the winter season and in June prior to the summer season.  Further information can be found here:

[4] On March 20 Greg Rickford, the Minister of Energy, Northern Development and Mines directed the IESO discontinuing the Conservation First Framework (CFF) and the Industrial Accelerator Program (IAP).  The Minister further directed that the IESO complete and achievable potential study for energy efficiency in the province by September 30, 2019. The Minister stated that while demand management programs have been successful in the province, these programs are less cost-efficient and less effective in meeting system needs.  The Minister issued a second directive to the IESO, also on March 20 to centrally deliver energy-efficiency programs implementing a new Interim Framework to take effect from April 1, 2019 to December 31, 2020. The Interim Framework includes the Retrofit Program, Small Business Lighting, the Energy Manager Program, Process and System Upgrades, Energy Performance Program, Home Assistance Program and energy-efficiency programming for Indigenous communities.

[5] More information on the TCA phase I design documents can be found here:

[6] Information on the application process of NERC and NPCC standards in Ontario can be found in IESO Market Manual Section 11: Reliability Compliance (  ORTAC can be found in Section 2.11 (

[7] This is sometimes characterized as “one day in ten years”

[8] Note that the Reliability Outlook uses a grid demand forecast.  Grid demand is net demand less embedded generation (i.e., Distributed Energy Resources (DERs))

Tennessee Valley Authority 2019 Renewables Request for Proposals

On April 1, 2019 the Tennessee Valley Authority (TVA) issued a Request for Proposals seeking at least 200 MW of renewable energy.[1]  The RFP is open to either stand-alone renewable energy resources or renewable energy resources with battery storage. The Commercial Operation Date (COD) deadline is no later than October 31, 2022, and all proposals must be submitted to TVA by May 15, 2019.

This announcement comes on the heels of TVA’s draft IRP and previous 2017 Renewable RFP, both of which indicate increased momentum by TVA to increase the amount of renewable energy in their resource mix. In February, TVA released their draft 2019 Integrated Resource Plan (IRP), which outlined potential capacity resource mixes over the next 20-years.[2] In contrast to an absence of any new capacity for coal, hydro, and wind, there was an increase in the amount of solar across all scenarios, with solar projected to expand by 3,700 to 8,800 MW by 2038.[3]  In its 2017 Renewables RFP, TVA executed several solar PPAs in partnership with Google and Facebook, with the power purchased by TVA via PPAs, and the technology companies repurchasing the power to satisfy the electricity requirements of various data centers.[4]

While the prices associated with the 2017 PPAs are not publicly available, Figure 1 provides points of comparison with a regional solar cost benchmark alongside some known PPA prices for recent projects in the Southeast US.  The regional solar Levelized Cost of Energy benchmark is based off the rate of decline from the Lazard V.10 and V.11 Southeast US LCOE.[5] While the regional benchmark is based on a theoretical project of 30 MW size, recent projects (including those reflected in Figure 1) in the Southeast are larger and would benefit from economies of scale and offer lower prices.  The River Bend solar project, which came online in 2016, is 75 MW in size and has a levelized price of $51 per MWh (in 2013 dollars).[6] The average PPA price across three solar projects resulting from Georgia Power’s 2017 Renewable Energy Development Initiative (REDI) RFP was reported as $36 per MWh.[7] These three projects were 200, 160, and 150 MW solar farms, owned by subsidiaries of First Solar, Invenergy Solar Development North America, and NextEra Energy Resources respectively (the First Solar project has since been sold to Origis Energy)[8]. Given these recent procurements, limited resource potential in TVA’s service territory, and the absence of wind in TVA’s draft IRP scenarios, opportunities for wind in response to this 2019 RFP seem unlikely.[9]

Figure 1: Cost Benchmark and Recent Southeastern Renewable Energy PPA Prices

*Forecast based on the percentage decline between the V.10 and V.11 Southeast Lazard forecast. Assumes a project size of 30 MW.


Power Advisory would welcome the opportunity to assist clients in assessing potential opportunities presented by TVA’s RFP, as well as other opportunities across the United States.


A PDF version of this report is here: Power Advisory TVA 2019 RFP

[1] TVA, “2019 Renewable RFP”. Link.

[2] TVA. 2019 Integrated Resource Plan. Link.

[3] TVA. 2019 Integrated Resource Plan. Section 7

[4] Google, Press Release. Knox News, TVA announces solar farms.

[5] Lazard LCOE, V.10; V.11. Assumes a crystalline utility-scale, 30 MW, solar project with a fixed-tilt design, and a 30-35% capacity factor for V.10 (2016) and 17-19% for V.11 (2017).

[6] Lawrence Berkley National Laboratory, Report.

[7] pv magazine, article. Georgia Power, Press Release.

[8] Origis Energy, Press Release.

[9] NREL, Section 7.6.10, Link.

Tennessee Valley Authority Draft IRP and Potential for Solar Development

On February 15, 2019, the Tennessee Valley Authority (TVA) released their draft 2019 Integrated Resource Plan (IRP), which outlines potential capacity resource mixes over the next 20-years.[1] The plan puts forth resource mix projections based on five different planning strategies and six scenarios for a total of 30 different outcomes. TVA will announce a preferred planning strategy after finalizing the IRP in summer 2019. Nonetheless there are still significant signals on future resource mixes within the draft plan. Notably, in contrast to an absence of any new capacity for coal, hydro, and wind, there is an increase in the share of solar across all projections, with differences between the amounts of utility-scale and distributed solar.[2]

Solar is projected to expand by 3,700 to 8,800 MW by 2038.[3] A large majority of these projected additions are utility-scale solar.[4] In two of the planning Strategies (A – “Base Case” and D – “Promote Efficient Load Shape”) all additions are projected to be utility-scale solar additions; and in the other three planning Strategies (B – “Promote DER”, C – “Promote Resiliency”, and E – “Promote Renewables”), there are varying amounts of distributed solar growth in addition to utility-scale growth. Exact numbers are not provided in the draft IRP, but the differences are visually illustrated in Figure 1 on the next page.

Results from past RFPs provide an indication of future opportunities for solar development. For example, a 2015 RFP for solar resulted in a 53 MW project owned and operated by Silicon Ranch.[5] More recently, as a part of TVA’s 2017 Renewables RFP and in partnership with Google, two 150 MW solar projects are being developed by NextEra Energy Resources and Invenergy. All power will be purchased by TVA via PPAs, with Google buying and using any power required for their data center needs.[6] This November, a similar partnership in scope and structure was made with Facebook, and the developers NextEra and First Solar.[7] While the more recent project was not attributed to the 2017 RFP, it is clear that regardless of what planning strategy is adopted by TVA, they see solar playing a significant role in their future energy mix.

Figure 1: TVA Nameplate Capacity – Solar Additions

Power Advisory would welcome the opportunity to assist clients in assessing potential opportunities presented by TVA’s draft IRP, as well as other opportunities across the United States.

[1] TVA. 2019 Integrated Resource Plan. Link.

[2] TVA. 2019 Integrated Resource Plan. Section 7.1.3 “Capacity Plans”

[3] TVA. 2019 Integrated Resource Plan. Section 7

[4] TVA. 2019 Integrated Resource Plan. Figure 7.7

[5] TVA, 2015 RFP, Link. News article, Link.

[6] Google, Press Release. Knox News, TVA announces solar farms.

[7] TVA, Press Release.


A PDF version of this post is available here: Power Advisory – TVA Solar Development Opportunity