Category Archives: Market Assessment

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

Context

  • 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

CONTEXT

  • 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).

BACKGROUND

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.

STAKEHOLDER FEEDBACK TO THE DEMAND OUTLOOK ENGAGEMENT SESSION

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].
POWER ADVISORY COMMENTARY

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).

OVERVIEW OF RESOURCE ADEQUACY PROCESS

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
POWER ADVISORY COMMENTARY

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.

[5]

CAPACITY ADEQUACY ASSESSMENTS

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.

POWER ADVISORY COMMENTARY

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

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

POWER ADVISORY COMMENTARY

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: http://www.ieso.ca/en/Sector-Participants/Planning-and-Forecasting/Technical-Planning-Conference

[2] Overview of MRP can be found here: http://www.ieso.ca/en/Sector-Participants/Market-Renewal/Overview-of-Market-Renewal

[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: http://www.ieso.ca/Sector-Participants/Planning-and-Forecasting/Reliability-Outlook

[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: http://www.ieso.ca/Sector-Participants/Engagement-Initiatives/Engagements/Meeting-Ontarios-Capacity-Needs-2020-2024

[6] Information on the application process of NERC and NPCC standards in Ontario can be found in IESO Market Manual Section 11: Reliability Compliance (http://www.ieso.ca/en/Sector-Participants/Market-Operations/Market-Rules-And-Manuals-Library).  ORTAC can be found in Section 2.11 (http://www.ieso.ca/-/media/Files/IESO/Document-Library/Market-Rules-and-Manuals-Library/market-manuals/market-administration/IMO-REQ-0041-TransmissionAssessmentCriteria.pdf?la=en)

[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

Eversource Acquires 50% Interest in Ørsted’s New England Leases and Northeast PPAs

Eversource announced February 8, 2019 that it had acquired a 50% interest in Ørsted’s Massachusetts North and Massachusetts South lease areas and its 700 MW Revolution Wind project and 134 MW South Fork Project.  Both projects are under development and have power purchase agreements (PPAs) with various Northeast electric distribution companies.

The purchase price of about $225 million (≈$540/kW assigning nominal value to the lease area), appears to represent a modest discount relative to what Ørsted recently paid for the Deepwater Wind holdings (≈ $630/kW assigning nominal value to the lease area). This possibly reflects the fact that Eversource didn’t acquire an interest in the operating Block Island Wind Farm, which as an operating largely de-risked asset would command a premium.

The deal provides Eversource with an investment runway to support its earnings growth target, which it needs after Northern Pass was denied by the New Hampshire Site Evaluation Committee and its Bay State Wind partnership with Ørsted failed to secure a contract in the first round of Southern New England OSW procurements.  With a US OSW portfolio that is comparable to Vineyard Wind’s and position as industry leader given the size of its worldwide OSW portfolio, Ørsted is a compelling partner.

The Eversource agreement provides Ørsted with cash and allows it reduce its exposure in the US Northeast.  Given the capital requirements for these projects, long development lead times, and limited permitting track record in the US, partnering for OSW development is a prudent strategy.   Furthermore, as the largest wires company in New England, Eversource represents an attractive partner as interconnection issues are likely to become more challenging for the second phase of Southern New England OSW projects.

IESO Energy Storage Advisory Group Recommendation Report Summary and Commentary

Date: January 21, 2019
For parties interested in: Energy Storage and innovation in Ontario

CONTEXT
• Independent Electricity System Operator (IESO) released “Removing Obstacles for Storage Sources in Ontario” report1 on December 19, 2018 based on consultation with its Energy Storage Advisory Group (ESAG).
• The report focuses on identified obstacles and mitigating strategies to help ensure fair
competition of energy storage resources in the Ontario electricity market.
• IESO makes a series of recommendations to support the mitigating strategies in the report; recommendations are for the IESO as well as the Ontario Energy Board (OEB) and the Ministry of Energy, Northern Development and Mines (MENDE).

BACKGROUND
As outlined in their Long-Term Energy Plan (LTEP) Implementation Plan, the IESO established the ESAG to “Identify potential obstacles to fair competition for energy storage with other technologies in the delivery of services and, where appropriate, propose mitigation strategies” 2. The ESAG3 was launched in April 2018 to advise, support and assist the IESO in evolving policy, rules, processes and tools to better enable the integration of storage resources within the current structure of the IESO-administered markets (IAM). The objectives of the ESAG are to:

• Support the IESO’s work to identify obstacles to fair competition for energy storage
resources;
• Provide input to the IESO’s work plan and/or list of priorities to address storage related issues and opportunities; and
• Advise, consult and coordinate discussions on issues which may affect storage participation in the existing IAM.

Energy Storage Advisory Group
The ESAG met monthly to identify potential barriers to energy storage, develop criteria and principles for assessment of the barriers, and finally develop mitigating strategies to the barriers. The ESAG and IESO identified thirty-five (35) obstacles to energy storage’s fair competition in the Ontario electricity market. The identified obstacles were sorted by the IESO based on those that were in scope (and would have a mitigation strategy developed) and those obstacles that were out of scope for the LTEP implementation plan objective.

Criteria for Identified Obstacles and Principles for Mitigating Strategies

The IESO applied criteria to each identified obstacle to determine if a barrier was in scope to develop a mitigating strategy. The main criteria question was:
• “Is storage prevented from, or burdened in, competing with other technologies in the
delivery of services that they are otherwise capable of providing?”
A “yes” to this criterion implies that the issue under consideration is an obstacle and warrants mitigation. If the answer to the main criteria was not clear, the IESO applied two additional test questions:

1) Are Ontario’s electricity market rules, codes and regulations able to accommodate the evolution and competition of new technologies such as storage resources? and
2) Is the treatment of storage resources, with respect to regulatory and market charges
consistent with the intent of those charges?

A “No” to either of these testing questions implies that the issue is an obstacle and warrants mitigation. Of the 35 obstacles identified by the ESAG, 15 were determined by the IESO to be in scope and appropriate to develop mitigating strategies for. A summary of the obstacles identified can be in a table at the end of this client note.
Mitigating strategies were developed under the guidance of the Market Renewal Program (MRP) Guiding Principles. The MRP is a comprehensive enhancement to Ontario’s wholesale electricity market design, addressing known issues with the market design. The principles of MRP are:

• Efficiency – lower out-of-market payments and focus on delivering efficient outcomes
to reduce system costs
• Competition – provide open, fair, non-discriminatory competitive opportunities for
participants to help meet evolving system needs
• Implementability – work together with our stakeholders to evolve the market in a
feasible and practical manner
• Certainty – establish stable, enduring market-based mechanisms that send clear,
efficient price signals

Find the full report in PDF format here.

Power Advisory Offers ISO-NE FCM Expertise

Ready to participate in the ISO-NE Forward Capacity Market? Or, need to understand the FCM as part of your development strategy, solicitation response preparation, or acquisition? Power Advisory can help you navigate the regions’ capacity market. With changes such as CASPR and the forward nature of the market, now is the time to understand the FCM.

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Three New Wind Energy Leases Offshore Massachusetts: Review of BOEM Auction Results and Competitive Implications

Over the last two days BOEM auctioned three leases offshore Massachusetts to Vineyard Wind, Mayflower Wind, and Equinor Wind. Vineyard Wind is a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, with an existing Massachusetts lease and a contract for an 800 MW project with the Massachusetts electric distribution companies (EDCs). Mayflower Wind Energy LLC is an affiliate of Royal Dutch Shell Plc. and EDP Renewables; it is the first position in the US OSW market for both companies.[1] Equinor is a Norwegian energy developer that holds the rights to the only existing BOEM lease offshore New York. This sale attracted historic attention from 19 qualified parties and 11 bidders. At the end of 32 rounds the total acquisition fee was $405.1 million ($135.1 million Vineyard Wind and $135 million for the other two winning parties).

Competitive Implications of ATLW-4A

Overall this should be a positive development for the competitiveness of the New England and broader Northeast OSW market. It introduces two new competitors to the region and strengthens Vineyard Wind’s position as an incumbent developer. Equinor represents a new competitor to the Southern New England OSW market. Equinor wouldn’t have been able to compete effectively in the Southern New England OSW market from its New York lease given the distance of this lease from New England and the associated incremental cost of transmission and the marginally worse wind resource in its New York WEA. While the primary opportunity will be for long-term contracts with the Southern New England EDCs, the projects from these lease areas should be able to compete in future New York procurements (which has a target of 2,400 MW by 2030) and possibly New Jersey (3,500 MW by 2030).

The interest of Equinor and Shell indicates the similarities of offshore wind and oil/gas development, both require significant engineering capability and careful management of project logistics, with significant capital requirements over an extended period of time before production begins.

The pricing relative to previous lease sales is a strong indication of market interest and the promise offered by the Northeastern OSW market. Adding two new competitors to the Southern New England market will enhance the competitiveness of solicitations. However, with one element of the evaluation criteria in the various OSW RFPs the project’s underlying maturity it may take a while for consumers to see the benefits of this increased competition.

Comparison to Atlantic Wind Lease Sales

Prior to ATLW-4A there have been 7 lease sales for 11 areas from North Carolina to Massachusetts. The average acquisition fee was $6.7 million. One of the first Massachusetts lease areas was acquired by OffshoreMW LLC (now Vineyard Wind) for as little as $150,197. The next highest sale after today’s results is the New York lease sale of OCS-A 0512 to Equinor in 2016 for a total acquisition fee of $42.5 million from 33 rounds of bidding by 6 total participants. Even in comparison to the New York sale the result of ATLW-4A is more than seven times greater.

Power Advisory_ATLW4A BOEM MA Lease Sale_2018-12-14

[1] Shell did qualify for the North Carolina lease sale (ATLW-7) in 2017 but did participate in the auction.

Review of Atlantic Offshore Wind Procurement Policy and Developments

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

New England

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

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

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

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

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

New York

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

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

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

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

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

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

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

New Jersey

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

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

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

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

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

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

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

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

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

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

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

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

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

 

A PDF of this update is available here.

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

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

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

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

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

 

Competitive Implications of Ørsted’s Acquisition of Deepwater Wind

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

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

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

Figure 1: Ørsted US Offshore Wind Portfolio

A PDF version of this memo is available here.