Author Archives: Jun-Xiong Sean Hughes

Massachusetts DOER Clean Peak Standard Update

On August 7th and 9th, the Massachusetts Department of Energy Resources (DOER) held informational meetings on the development of the Clean Peak Standard (CPS), which would require retail energy suppliers to procure a portion of their supplies from clean energy resources produced (either through generation or energy storage) during defined peak periods.

During these meetings a summary of the draft regulation was reviewed, which highlighted key features of the program:

  • The CPS will require retail electricity suppliers to meet a Minimum Standard Obligation, which will be a percentage of annual electricity sales. Starting in 2020, the minimum obligation will be 1.5% of retail electricity sales, and will increase by 1.5% each year, reaching 16.5% by 2030.
  • To meet the obligations, retail electricity suppliers purchase Clean Peak Energy Certificates (CPECs). The CPECs are generated during Seasonal Peak Periods by qualified Clean Peak Energy resources, which include:
    • New (in operation on or after 1/1/19) RPS Class I eligible resources
    • Existing RPS Class I or II resources paired with a Qualified Energy Storage System
    • Qualified Energy Storage System
    • Demand Response Resources
  • The number of CPECs generated is determined by the resource’s output during the Seasonal Peak Period with different multipliers applied for different seasons and to align production with various policy incentives (e.g., promoting resilience). Additionally, CPECs will be generated during the monthly system peak, which will be determined retrospectively at the end of the month.
    • Seasonal Peak Periods have been initially identified by DOER as the following:

For existing RPS Class I or II Resources paired with energy storage, the storage system must be at least 25% of the nameplate capacity of the RPS resource and offer a minimum of 4 hours of storage. DOER noted that this was to discourage large, existing RPS resources from being paired with a small storage system, resulting in minimal shifting of renewable energy production.

Qualified Energy Storage Systems must operate to primarily to store and discharge renewable energy. There are four options to demonstrate this:

  1. The storage system is co-located with an RPS Class I or II resource;
  2. The storage system is paired (operationally or contractually) with an RPS Class I or II resource.
  3. The storage system aligns charging periods with the designated charging windows defined by the DOER as shown below.
  4. The storage system has an operational schedule in their interconnection service agreement that demonstrates the “resolution of intermittency-based power issues”

CPEC multipliers are used to determine how much CPECs are generated from any qualified resource’s performance. Some multipliers are less than 1, effectively discounting the value of existing or contracted RPS Class I and II resources. The chart below summarizes these multipliers.

In a departure from the earlier SREC programs (SREC 1 and 2), DOER will collaborate with the EDCs to procure CPECs under long term contracts from suppliers. These long-term contracts will be a complement to the open market.

Next Steps

DOER plans to have a draft regulation filed by Q4 2019, which will kick-off a formal comment period and public hearings on the draft regulation. Q1 2020 is the target for the promulgation of the final regulations.

Key Questions

  1. Where will the market for CPECs settle?

DOER has proposed an Alternative Compliance Payment (ACP), which effectively represents a ceiling of $30 for CPECs. With battery storage anticipated to be the marginal resource that sets the price for CPECs, what revenues are needed from CPECs beyond anticipated energy and capacity market revenues?

  • What other value stacking opportunities are there?

The cycling requirements of the CPS are likely to limit these.

  • What are preferred project configurations?

Is the resilience multiplier sufficient to overcome economies of scale offered by larger projects that don’t benefit from this multiplier?

  • Is there sufficient revenue certainty given the program design?

DOER has proposed an optional procurement process for electric distribution companies. Fixing the price for CPECs doesn’t address the quantity risk associated with changes in the duration of Seasonal Peak Periods and changes to CPC multipliers. Will DOER mitigate this risk in the final program design?

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

Review of Massachusetts Compromise Bill ‘An Act to Promote a Clean Energy Future’

On July 30, 2018, the conference committee appointed to reconcile the Senate and House clean energy bills finalized a compromise bill, H.4857. The bill’s contents more closely align with the House of Representatives bills passed last week (H. 4756 and H. 4739) than the omnibus Senate bill (S. 2545) (see Power Advisory’s report on the differences between the initially proposed bills). The House and Senate voted in favor of the bill on July 31, the last day of the legislative session.

Renewable Portfolio Standard

The compromise bill will increase the state’s Class I Renewable Portfolio Standard (RPS) at the rate proposed by H.4756. Between 2020 and the end of 2029, the rate would increase to 2% per year. After 2030, it would return to the current growth rate of 1%. The rate will ensure that the state procures 35% of Class I renewables (new resources) by 2030.

Offshore Wind

The bill directs the Department of Energy Resources (DOER) to conduct a cost benefit analysis for the procurement of an additional 1,600 MW of offshore wind by the end of 2035 and “may require said additional solicitations and procurements.”  This suggests that DOER doesn’t require additional legislative authority to mandate the distribution companies to solicit and procure this additional 1,600 MW of offshore wind.  The DOER can also require distribution companies to hold competitive procurements for offshore wind transmission to deliver energy from designated wind energy areas as long as it can serve more than one project. The transmission service cannot exceed 3,200 MW of total capacity. The procurement of offshore wind transmission must be the most cost-effective means to deliver offshore wind.

Interestingly, in the filing letter that it submitted to the Massachusetts Department of Public Utilities (DPU), DOER expressed strong support for the 800 MW Vineyard Wind Project and asserted that the “Project is highly cost-effective [and] significantly aligns with the Commonwealth’s goals of creating a clean, affordable, and resilient energy future for the Commonwealth.”  This clearly suggests that DOER has a favorable view of offshore increasing the likelihood of DOER mandating the procurement of an additional 1,600 MW of offshore wind.

Clean Peak Standard

The bill also provides for the creation of a Clean Peak Standard (CPS) for all retail electricity suppliers, which was detailed in H. 4756. The CPS will be in place starting January 1, 2019 and will require each retail electric supplier to meet a baseline percentage of sales with clean peak certificates. The clean peak certificate would be a credit received for each MWh of energy or energy reserves provided during a seasonal peak period. After 2019, every retail electricity supplier must provide a minimum of at least an additional 0.25% per year of sales met with clean peak certificates.  The legislation defines seasonal peak periods as the times when net electricity demand is the highest. The periods must be more than one hour but less than four hours in any season. A clean peak resource according could be any qualified RPS resource, an energy storage system, or a demand response resource that delivers energy to the distribution system during seasonal peak periods or can reduce load on the system. The DOER will need to establish the procurement mechanism of the certificates, the percentage of kilowatt-hour sales from clean peak resources, the seasonal peak periods, and an alternative compliance mechanism.

Energy Storage

Massachusetts’ current energy storage target is 200 MWh by 2020. The compromise bill increases this target to 1,000 MWh by December 31, 2025. Neither the House nor Senate bills included this specific target. Similar to H. 4739, the comprise bill will require electric distribution companies (EDCs) to file an annual distribution system resilience report that would highlight areas of the distribution system where non-wires alternatives could serve as system resiliency measures. EDCs can hold competitive solicitations for such non-wires alternatives. The legislation provided guidance on which monetary and non-monetary factors to be considered in a solicitation, which include: 1) resiliency improvements, 2) reduce greenhouse gas emissions, 3) reducing peak demand, 4) reducing congestion in constrained areas, and 5) benefits to low-income areas.

Power Advisory would welcome the opportunity to assist clients in understanding the opportunities created by these changes to the Commonwealth of Massachusetts’ clean energy policies.

A PDF version of the report is available here.

Review of Massachusetts House of Representatives Energy Bills Relative to the Senate’s ‘An Act to Promote a Clean Energy Future’

The Massachusetts House of Representatives passed two major energy bills on July 12, 2018. The bills address a subset of the legislation that was approved by the Massachusetts Senate omnibus clean energy bill (S. 2545) in June. The House bills are now in conference committee with the Senate and are expected to be reconciled ahead of the close of the legislative session on July 31.

Renewable Portfolio Standard

H.4756 would increase the state’s Renewable Portfolio Standard (RPS) to promote an accelerated procurement of renewable energy. Currently, the minimum percentage of Class I renewable energy that Massachusetts’ retail electricity suppliers must provide customers increases 1% per year through 2050. In the legislation, this rate would increase to 2% each year starting in 2021 through 2030. After 2030, it would return to the current growth rate of 1%. The increased rate would raise the RPS from the current target of 25% by 2030 to 35% by 2030. This goal is less aggressive than the Senate’s bill, which called for a 3% annual increase and an ultimate target of 100% renewable energy in the state by 2047.

Offshore Wind

H.4756 would also increase the state’s offshore wind procurement target to 3,200 MW by 2035, doubling the current procurement target of 1,600 MW by 2030. While this target is a significant increase to current levels, it is far less than the goal of 5,000 MW of OSW capacity by 2035 put forward by the Senate in S. 2545. With either target, Massachusetts is signaling that it is interested in making further commitments to the emerging US OSW industry. An increased procurement target will provide additional opportunities for the three existing wind energy lease holders and increase the value of the two remaining MA lease areas being auctioned by BOEM through ATLW-4A this fall.

Clean Peak Standard

H.4756 also includes a provision for the establishment of a Clean Peak Standard (CPS) for all retail electricity suppliers. Such a standard would ensure that Renewable Portfolio Standard (RPS) and greenhouse gas emissions reductions are met by having clean energy generation in peak load hours instead of fossil fuels. According to the bill text, the CPS could be similar to the state’s existing RPS, but the methodology would be established at a later date. If similar to the RPS, each retail electricity supplier would need to meet a certain percentage of their total sales with clean peak certificates, similar to renewable energy certificates (RECs) under the RPS. The clean peak certificate would be a credit received for each MWh of energy or energy reserves provided during a seasonal peak period. The legislation defines seasonal peak periods as the times when net electricity demand is the highest. The periods must be more than one hour but less than four hours in any season. A clean peak resource according to the legislation could be any resource that qualifies under the RPS, an energy storage system, or a demand response resource that delivers energy to the distribution system during seasonal peak periods.

Also, similar to the procurement of RECs, regulations could include a process through which clean peak certificates are competitively procured and electric distribution companies would enter into long-term contracts ultimately approved by the Department of Public Utilities. Seasonal peak periods would need to be established as well as an alternative compliance mechanism.

By the end of this year, the Department of Energy Resources (DOER) will determine the current kilowatt-hour sales from existing clean peak resources during seasonal peak load hours. This will be used to establish a baseline percentage of sales that must be met with clean peak certificates beginning on January 1, 2019. After 2019, every retail electricity supplier must provide a minimum of at least an additional 0.25% of sales that must be met with clean peak certificates. The procurement of clean peak certificates will not apply to municipal light plants.

The House’s bill is a response to Governor Baker’s legislation entitled “An Act Promoting Climate Change Adaptation, Environmental and Natural Resource Protection, and Investment in Recreational Assets and Opportunity.” This legislation called for a Clean Peak Standard. The Senate bill did not include language pertaining to a Clean Peak Standard.

Energy Storage

Massachusetts’ current energy storage target is 200 MWh by 2020. The Senate bill aimed to increase this target to 2,000 MW by 2025. While not increasing the energy storage procurement target, H. 4739 addresses the need for additional integration of storage into the transmission and distribution grids.

The bill would require electric distribution companies (EDC) to file an annual distribution system resilience report which will include maps that show the most congested areas of the distribution system as well as areas most vulnerable to power outages. These maps could serve as a basis for identifying areas that would require system upgrades that could be deferred or replaced by non-wires alternatives. Each EDC could then hold a competitive solicitation for now-wires alternatives (such as energy storage) from third-party developers that would serve a resiliency need of the grid. The Senate bill did not mention non-wires alternatives or a resilience report.

Greenhouse Gas Emissions

One topic that was not addressed in the House bills was greenhouse gas emission reductions. The Senate bill established additional interim GHG reductions goals of 35-45% below 1990 levels by 2030 and 55-65% below 1990 levels by 2040, beyond the existing goal of a 25% reduction by 2020. These new interim goals could help the Commonwealth stay on track to meet its economy-wide mandate for an 80% reduction in GHG emissions below 1990 levels by 2050 established in the Global Warming Solutions Act of 2008. Furthermore, S. 2545 directs that a market-based system to reduce emissions from the transportation sector be implemented by 2021, for the commercial and industrial building sectors by 2022, and for the residential building sector by 2023.

Power Advisory would welcome the opportunity to assist clients in understanding the opportunities created by potential changes to the Commonwealth of Massachusetts’ clean energy policies.

A PDF version of the report is available here.

Review of NYSERDA’s 2018 Renewable Energy Standard RFP

On April 25, New York Governor Andrew Cuomo announced the second Request for Proposals (RFP) for large renewable generation projects under the Renewable Energy Standard (RES), a component of the Clean Energy Standard (CES). The solicitation will be conducted by the New York State Energy Research and Development Authority (NYSERDA). The RFP is for approximately 1.5 million MWh of Tier 1 Renewable Energy Certificates (RECs) per year. The CES was adopted in 2016 and calls for 50% of the state’s electricity to be generated by renewable energy resources by 2030 (also known as the “50 by 30” goal).

A few new provisions were added in this solicitation that were not included in the first solicitation in 2017. NYSERDA will favor renewable energy projects that avoid overlap with prime agricultural land. In addition, the state is encouraging proposals that consist of renewable energy pairing with energy storage and supports Governor Cuomo’s commitment to deploy 1,500 MW of energy storage by 2025.[1] The RFP provides for an in-service date prior to November 30, 2022.

The RES is the state’s main way of achieving the CES goal. Under the RES, all Load Serving Entities in the state must procure new renewable resources (called Tier 1 resources) annually as increasing percentages of their total load. The compliance mechanism is the procurement of RECs. The RES requires NYSERDA to conduct regularly scheduled solicitations for the long-term procurement of RECs. These are called RES RFPs. The first of which took place in 2017, in which approximately 3,200,000 MWh of generation was procured. For this second solicitation, eligible technology types are: biogas, biomass, liquid biofuel, fuel cells, hydroelectric, tidal/ocean, solar, and wind. If the project’s first commercial operation date is on or after January 1, 2015, it is eligible for this solicitation. However, older projects may be eligible if they have undergone significant upgrades after 2015 or if an otherwise eligible unit is returned to service after 48 consecutive months of being out of commercial operation. Imports from control areas that are adjacent to the New York Independent System Operator (NYISO) can be eligible Tier 1 resources.

The solicitation process consists of three steps. Step One is the Resource Eligibility Determination in which NYSERDA confirms that the bid facility meets the Tier 1 resource general eligibility requirements. If the bid facility is deemed eligible, it then must submit Step Two – Application for Qualification. In Step Two, NYSERDA will evaluate the application package to ensure that the bid facility meets or exceeds a minimum threshold in each of five Minimum Threshold Qualification categories. These categories are: site control, interconnection, permitting, project development, and resource assessment. Bid facilities that meet the minimum Threshold Qualifications will move on to Step 3 – the Bid Proposal where proposals will be evaluated and scored based on: (1) the Bid Price, which will be weighted at 70% of the overall score, and (2) non-price factors.  The non-price factors will have a combined weight equaling 30% of the overall score allocated in terms of: (1) 10% Incremental Economic Benefits to New York State; (2) 10% Project Viability beyond the Minimum Thresholds; and (3) 10% Operational Flexibility and Peak Coincidence.

The solicitation timeline is outlined below:

Table 1: Solicitation TimetableSource: NYSERDA

Since this is a REC-only procurement, renewable project developers will have to manage energy price risks. The following figure illustrates the average levelized future prices per zone for 2019-2027:

Figure 1: NYISO Levelized Futures Prices from 2019-2027

Source: SNL, Power Advisory

As shown in Figure 1, the lowest energy prices can be expected in Zones E and D. Project developers will have to strategically determine the best location to site their project to receive higher energy prices.

[1] 10% of the points in the final stage of the evaluation will be allocated based on operational flexibility and peak coincidence.

A PDF version of this report is available here.

Review of Possible Massachusetts Clean Peak Standard

Last week, Massachusetts Governor Baker submitted legislation to the Massachusetts Senate and House, “An Act Promoting Climate Change Adaptation, Environmental and Natural Resource Protection, and Investment in Recreational Assets and Opportunity”, as a key part of the administration’s Climate Change strategy.  The Legislation included $1.4 billion in capital authorizations for climate adaption and resilience.  Of particular relevance to New England’s electricity sector was a Clean Peak Standard that would require the Department of Energy Resources to establish a standard that requires “all retail electricity suppliers to provide a minimum percentage of kilowatt-hour sales to end-use customers in the commonwealth from clean peak energy resources.”

A Clean Peak Standard was first proposed by Arizona’s Residential Utility Consumer Office to ensure that a certain percentage of energy delivered to customers during peak load hours is delivered from clean energy resources.  Such a standard can help ensure that the environmental objectives of a renewable portfolio standard (RPS) are promoted and not frustrated by a significant reliance on fossil fuel generating resources during peak load hours.  RPS promote resources that provide the lowest cost energy, but with wind and solar providing the vast majority of such energy they can lead to an oversupply of energy in some periods (as reflected by negative market prices) and increases in the requirements for more flexible dispatchable resources in other periods.  This is illustrated by the Duck Curve, which reflects the significant increase in ramping capability that is required as result of the increased penetration of solar energy resources.  Figure 1 below shows California’s Duck Curve and the dramatic increase in the requirements for fast-responding resources, a significant proportion of which is likely to be natural gas-fired, from 4 to 7pm.

Figure 1: Net Load in California after Variable Resources: the “Duck Curve”

Source: CAISO (

The Clean Peak Standard would require that a portion of qualifying electricity production be produced during the designated peak period to limit the need for natural gas-fired generating units that are commonly called upon to provide such a ramping capability.  Specifically, to qualify under the conditions reflected in Figure 1 generating resources would need to produce energy from 4 to 7pm and utilize a clean energy resource to produce this energy.  The filed legislation defines eligible resources as Class I renewable energy resources (which presumably would have to be dispatchable or schedulable), energy storage resources (which presumably would be charged with clean energy), or demand response resources.

With an objective to incent the development of new resources, rather than to increase the compensation realized by existing resources, there is likely to be a requirement that these be new resources.  This presents special challenges to demand response resources where it is more difficult to ensure that the resource is in fact incremental and not an existing resource seeking to secure higher revenues from a higher value market.  Similarly, energy storage resources presumably will need to demonstrate that the energy used for charging is “clean” and incremental.

The legislation calls for the Clean Peak Period to be when “electrical consumption results in a significant increase in greenhouse gas emissions, or an increase in electrical prices or transmission and distribution costs to end-use electricity customers” and be no more than 10% of the hours in the year.

Power Advisory would welcome the opportunity to assist clients in assessing opportunities created by the Clean Peak Standard regulation.

John Dalton, President, Power Advisory LLC

A PDF version of this report is available here.

Funding Opportunity: NRCan Emerging Renewable Power Program

On January 18, Canada’s Minister of Natural Resources, Jim Carr, announced the launch of an expression of interest for the Emerging Renewable Power Program (ERPP). The program was created to expand the portfolio of commercially viable renewable power technologies available in Canada, deploy demonstrated technologies at the utility scale, and achieve further electricity sector greenhouse gas emission reductions.

ERPP’s anticipated C$200 million in funding is part of the investment goal of C$21.9 billion that the federal government plans to roll out over the next 11 years under the Pan-Canadian Framework on Clean Growth and Climate Change. The collaborative plan was officially adopted in December 2016 by all provinces and territories, except for Saskatchewan and Manitoba, and targets a GHG emission level of 523 metric tons by 2030 (a 30% reduction from 2005 levels).

Source: Pan-Canadian Framework on Clean Growth and Climate Change, 2016

The funding opportunity is available to renewable power technology projects that satisfy the following eligibility requirements:

  • Meet the definition of an emerging renewable energy technology
  • Produce electricity for sale or use in Canada
  • Renewable power technologies established commercially, but have yet to be established in Canada; or
  • Renewable power technologies available in Canada, but have yet to be implemented on a utility scale
  • Minimum Capacity:
    • 4 MW for geothermal, offshore wind, tidal, and concentrated solar projects
    • 1 MW for emerging technologies, such as next-generation biomass, river current, other marine resources and new solar technologies
  • Help meet the commitments made under the Pan-Canadian Framework on Climate Change

Strategic environmental assessments for energy planning purposes may also be submitted to this program. Projects that are able to commission during the funding period of April 1, 2018 to March 31, 2023 will be given priority. A per project funding limit of $50 million for up to 50% of eligible project expenditures is established in the Expression of Interest. However, greater than $50 million may be available with approval from the Treasury Board, such as for offshore wind which is likely to require more than the limit due to project size.

Expression of Interest (Due Feb. 11, 2018)

An expression of interest is now open but is not a prerequisite to participate in the forthcoming Request for Proposals. NRCan plans to use the expressions of interest to more accurately determine the level of funding that will be made available and the number of projects that can be expected to be funded.

Interested parties can receive the application package by submitting an email with company name, project name, and contact information. For your convenience we have made a copy of the EOI Applicant Guide and form on our website. The application requests details regarding applicant entity, general project information, and costs. The expression of interest application should be returned in Excel format along with a PDF of the signatory page by February 11, 2018, 11:59 pm EST.

Request for Proposals (Due Q3/Q4 2018)

Following the closure of the EOI process, the program will launch a Request for Proposals. Applicants will have approximately two months to complete the proposal template, which will be made available in the coming months. Our expectation is that the RFP could be released as soon as Q2 or Q3 2018.

Power Advisory would welcome the opportunity to support responses to the Emerging Renewable Power Program and to assess opportunities for emerging power technologies across North America’s electricity markets.

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

A PDF version of this report is available here.