While the announcement of combined solicitations for 4,000 MW of offshore wind (NYSERDA) and land based renewables (NYSERDA & NYPA) on July 21, 2020 was historic, this is the continuation of a ramp up in renewables procurement in New York State and indicative of what is required for the state to meet its goals established in the Climate Leadership and Community Protection Act.[1] In the last three years, 2017-2019, NYSERDA has contracted about 6,000 MW of large scale renewables. The state’s procurement will not stop in 2020. NYS will continue to be an attractive market for clean energy development offering opportunities for long term contracts.
Figure 1: NYSERDA Large Scale Renewables Contract Awards (2013-2019)
Additional contracting opportunities to NYSERDA’s centrally administered solicitations (noted in Figure 1) include procurements by the New York Power Authority, Long Island Power Authority and institutional buyers such as the New York Higher Education LSRE. To contextualize this recent procurement and where the state is heading on its path to achieving 70% renewables by 2030 and 100% carbon-free electricity by 2040, Power Advisory offers the following summary timeline highlighting NYS’s climate and energy policies; solicitations and awards; as well as related clean energy announcements from recent years.
Figure 2: New York State Clean Energy Timeline
At least 25% of the projected 2030 system supply mix has yet to be contracted by NYSERDA. This equates to about 40,000 GWh or 11.5 GW of land-based renewables and 4.1 GW of offshore wind to be contracted.[1] These requirements could be even greater if there is higher than expected load growth with strategic electrification (estimates based on NYSERDA’s 2030 load estimate of 151,678 GWh), attrition of contracted projects, and retirement of baseline and off-contract resources (which produce about 39,000 GWh annually).
Figure 3: New York’s Projected 2030 Generation Mix
Last month the New York State Energy Research and Development Authority (NYSERDA) and New York Department of Public Service (DPS) published a White Paper on Clean Energy Standard Procurements to Implement New York’s Climate Leadership and Community Protection Act. This White Paper aims to provide a framework to better align the state’s Clean Energy Standard (CES) with its Climate Leadership and Community Protection Act (CLCPA) passed in 2019 while also utilizing the existing CES procurement structure to achieve the state’s target of 70% renewable energy by 2030. In part, within this White Paper NYSERDA and the DPS staff propose the addition of a Tier 4 to the CES in order to promote greater renewable energy delivery into New York City (NYISO Zone J).[1]
In 2019, New York City alone represented 33% of state electricity consumption. Whereas the Tier 1 and predecessor Main Tier Program has resulted in the development of renewable energy largely in the upstate region. The new Tier 4 Program focuses on bringing more renewable energy downstate, specifically to New York City. The proposed program would provide financial support for renewable energy transmitted into Zone J and create a procurement structure distinct from the procurement for offshore wind which will also interconnect downstate.
As proposed, any renewable energy system will be eligible under the Tier 4 Program, as long as it has a commercial operation date (COD) on or after the publication date of any New York Public Service Commission order authorizing this new tier. The White Paper outlays the delivery requirement as the renewable project must either be located in Zone J or involve a new transmission connection to deliver renewable energy to Zone J. Tier 4 RECs would also be eligible to meet compliance standards set by New York City Local Law 97, which aims to reduce building emissions but allows RECs delivered to the city to serve as an alternative form of compliance.
Importantly, the eligible resources are proposed to include the full complement of renewable resources including large scale hydropower. In this way the procurement is expected to have a number of similarities to the Massachusetts 83D renewable energy procurement that resulted in the selection of the 1,200 MW New England Clean Energy Connect (NECEC) to import hydropower from Hydro-Québec. Similarly, given that CES Tier 4 resources will have to be delivered to New York City this proposal is likely to support the development of new transmission.
However, there are some key differences that are likely to result in greater opportunities for non-hydroelectric renewable energy resources from upstate New York and/or Canada. In the White Paper, NYSERDA seeks the ability to procure RECs from hydropower that does not involve new impoundments and is additional to the baseline production of energy from the supplier. Effectively these constraints are likely to limit the Tier 4 opportunity to hydro units that are already under construction or hydro energy that was previously spilled and also seeks to prevent hydroelectric energy from being diverted from other markets.
The White Paper recommends a procurement target for Tier 4 resources of up to 3,000 MW and suggests using the same solicitation and contracting process as used for Tier 1 resources. This process would include negotiating the COD on an ad hoc basis as well as allowing NYSERDA to enter into contracts with a tenor of up to 30 years and with multiple entities as necessary. The White Paper also proposes enabling NYSERDA to solicit both Fixed and Indexed REC bids under Tier 4 with a price cap. This price cap aims to ensure that renewable penetration into New York City increases without undue ratepayer impacts. Similar to Tier 1, compliance with the Tier 4 would be the financial responsibility of all load serving entities (LSEs) but the program would be centrally administered by NYSERDA.
Next Steps
With the publishing of the White Paper in docket 15-01168/15-E-0302, a 60-day public review and comment period was initiated. After which the Commission will act on the proposals in the White Paper and issue any orders determining the program design and implementation.
[1] The White Paper’s other proposals are not reviewed within this Power Advisory client note.
John Dalton, President; Carson Robers, Senior Consultant; and Sophia Vitello, Research Analyst
Power Advisory is offering a subscription-based service for Ontario price and Global Adjustment forecasts and Alberta price forecasts. Along with forecasts we offer our electricity market update reports for Ontario and Alberta. In addition, we offer bi-monthly calls to subscribers featuring commentary on latest developments from each market through interactive one-hour discussions.
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While most Class I REC markets across the country are generally oversupplied, the smaller New England Class I REC market stands apart as recent events have driven prices dramatically higher over the last year (Figure 1). In fact, 2019 vintage Class I RECs have climbed all the way from $7/REC a year ago to about $40/REC today, a stunning 5.7x increase. This suggests a shortage of RECs available in the marketplace to compliance entities who need to meet state Renewable Portfolio/Energy Standards.
Figure 1. 2019 Vintage ISO-NE Class I REC Prices, Last 12 Months ($/REC)
Source: S&P Global, Power Advisory analysis
The main factor influencing the REC market
is the anticipated timing of completion of a series of large offshore wind
projects. There are currently 2,304 MW under contract in New England (including
the 804 MW Mayflower Wind project which is negotiating PPAs with the
Massachusetts electric distribution companies) and more expected in the future
(namely an ongoing Connecticut procurement process for up to 2,000 MW). While
the 800 MW Vineyard Wind project owned by Avangrid Renewables and Copenhagen Infrastructure
Partners had appeared construction-ready, and almost at financial close, it
suffered a setback when the Bureau of Ocean Energy Management (BOEM) delayed
the project’s federal permitting on August 9, 2019. BOEM has mandated that Vineyard
Wind to go through a supplemental draft Environmental Impact Statement (EIS)
process that takes account the cumulative impacts of offshore wind development
in the region.The timing of this analysis is unclear and is subject to normal
public comment and review. Vineyard Wind is expected to be delayed at least six
months, with potential knock-on effects for the rest of the offshore wind pipeline.
Other significant events that have driven
prices higher by increasing REC demand or reducing supply include:
Maine increasing its RPS in
June 2019 following the election of a new clean energy-friendly governor last
year, and
National Grid selecting only
one significantly smaller solar project for negotiation from its 400 MW
renewable RFP in Rhode Island.
But it’s the offshore wind that is the big
driver. Assuming a 48% capacity factor, the three ISO-NE utility-scale offshore
wind farms alone that are under contract, consisting of Vineyard Wind (800 MW),
Revolution Wind (700 MW) (Orsted/Eversource) and Mayflower Wind (804 MW)
(Shell/EDPR), would generate almost 10 million MWhs when they are connected to
the grid. Should those projects be connected by 2030 as expected, the modest
amount of onshore renewables recently contracted come online, and trends in
behind-the-meter solar continue, a gap of about 11 million MWhs would remain to
meet RPS requirements within
New England as a whole. However, Connecticut’s targeted 2,000 MW procurement
and an additional 1,600 MW of offshore wind planned by the Massachusetts
Department of Energy Resources will fill – and then exceed – the estimated gap.
When considering the balance of the REC market it is important to note that each state has its own renewables standards and procurement statutes, with respective definitions, eligibility requirements and targets (see Figure 2 for the current Class I equivalent standards). Furthermore, RECs are tradable within ISO-NE and from adjacent control areas.
Figure 2. Current New England Class I Standards Through 2050
Once the contracted offshore wind projects
reach commercial operation, expected to be in the 2023-2026 time frame, Class I
REC pricing will presumably stabilize and then begin eroding as the much needed
RECs hit the market. Until then, the pricing could remain high, as the market
appears to be undersupplied. The additional 3,600 MW of offshore wind expected to
be contracted by Connecticut and Massachusetts will result in an oversupplied
market starting in the late 2020s.
Alternative Compliance Payment (ACP)
The alternative compliance payment (ACP)
acts as ceiling to the market. The ACP is $70.44/REC in Massachusetts for 2019
and $55.00/REC in Connecticut. Thus, current bid-asks as lofty as $46/REC
according to the Intercontinental Exchange, or 84% of the CT ACP, signal that
we are nearing or at an undersupplied market. That’s because the alternative is
to pay the ACP which is not that much higher.
New Build Capacity to Meet 2030 Targets
As noted above, Power Advisory estimates that
the incremental 3,600 MW of offshore wind expected from Connecticut and
Massachusetts in addition to the current renewables contracts and supply would
entirely satisfy the 2030 New England RPS requirements. The aggressive offshore
wind procurement targets combined with high capacity factors squeeze out opportunities
for onshore wind and solar assets that have been used to comply with RPS to
date. This is not to say that there are not onshore renewables development
opportunities. For example, Maine will be issuing two near term Requests for
Proposals for the equivalent of 14% of its 2018 retail electricity sales
(discussed in Power Advisory’s July note on
recently enacted legislation in the state).
Expected Long Term REC Pricing
Following the current New England Class I REC price spike, we expect prices to stabilize and then erode as the project development process catches up with the mandates, driven mainly by offshore wind and to a lesser extent, the Massachusetts SMART program and other procurements. Longer term (post-2030), we expect an oversupply of RECs leading to a substantially lower REC prices. Projects will become less reliant on RECs over time. Future regulatory and policy announcements, load growth due to electrification, or substantial retirements could support higher prices.
Power Advisory welcomes the opportunity
to assist clients’ understanding of the New England REC market and assessment
of renewables development in the region.
Toronto,
Ontario, November 6, 2019 –
Power Advisory LLC (Power Advisory) has initiated the procurement process for
an in-stream tidal energy demonstration project in Nova Scotia, which offers one
of the largest tidal energy resources in the world.
In
October Power Advisory was appointed as the Procurement Administrator for this
procurement process by the province of Nova Scotia. As Procurement
Administrator, Power Advisory will be responsible for ensuring that the
procurement is fair, transparent and competitive. The province will consider
projects with nameplate capacity of no more than four megawatts. Projects are
to be restricted to Berth D within the Fundy Ocean Research Centre for Energy
(FORCE) marine renewable-electricity area. Project selection and subsequent
awarding of a Marine Renewable-Electricity Licence and Power Purchase Agreement
is conditional upon providing adequate financial security for the retrieval and
disposal of the abandoned CSTV turbine at the site. Power Advisory expects to
open the Call for Applications process in the near future, concurrently with
the request for approval of the Power Purchase Agreement from the Nova Scotia
Utility and Review Board.
Further
details regarding the procurement process will be shared with parties that have
registered on the website shortly. The procurement objectives are to achieve
the best value for Nova Scotia ratepayers and to support the advancement of
Nova Scotia’s marine renewable energy sector.
Power
Advisory is a leading North American management consulting firm offering
extensive knowledge of the Nova Scotia electricity sector and has deep
expertise in renewable energy competitive procurements. Power Advisory
previously served as the Renewable Electricity Administrator in Nova Scotia,
overseeing the 2012 Request for Proposals (RFP) for 300 GWh of renewable energy
from Independent Power Producers (IPPs).
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:
The storage system is co-located with an RPS Class I or II resource;
The storage system is paired (operationally or contractually) with an RPS Class I or II resource.
The storage system aligns charging periods with the designated charging windows defined by the DOER as shown below.
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
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?
Two weeks ago New York State announced that they were negotiating contracts with two OSW projects totaling 1,696 MW, with 2024 commercial operation dates (COD), a year when additional 1,348 MW is scheduled to enter commercial operation: Ørsted US Offshore Wind’s (Ørsted’s) 1,100 MW Ocean Wind Project and US Wind’s 248 MW Maryland project. With this the US Northeast/Mid-Atlantic has awarded or is anticipated to award this year OSW contracts representing over 6,000 MW. These are shown by their anticipated COD and developer below.
* Ørsted projects are with various partners including Eversource, PSEG and Dominion.
These projects will result in cumulative investment of about $22 billion and about 13,000 direct jobs (FTEs) and a total employment impact of over 42,000 during the construction period. This is a quick start to a major new industry where the supply chain to support it is just beginning to be developed. An obvious question is: can this industry develop at this pace, without significant and costly growing pains? While there are many challenges, work appears to be underway to address some of the largest pinch points. Oft-cited examples include ports, vessels and qualified labor in some trades (ex. metal fabrication and marine services).
States and OSW developers are aware of the port constraints and are seeking to ensure that the necessary investments have been made to enable the construction of these projects at reasonable costs and without undue delays. Based on our assessment some gaps are that Vineyard Wind appears to need an additional port for its 800 MW contract with the Massachusetts EDCs beyond the New Bedford Marine Commerce Terminal and Equinor is in need of a port for marshalling, but New York State has earmarked $200 million for near term port development.
Sufficient suitable vessels are another possible constraint. The Jones Act and port infrastructure clearly will shape the vessel spreads that developers will employ. While there are reportedly Jones Act compliant OSW installation vessels under construction, vessels and port restrictions including their size (both laydown area and quayside length), air draft restrictions and available infrastructure present challenges.
With respect to labor force constraints, this level of OSW development would result in about 2,400 fabricated structural metal manufacturing jobs and 1,600 marine services jobs (FTEs) during the construction period and over 500 OSW maintenance jobs. These are three areas with particular needs that could outstrip available resources, without training. However, numerous investments being made by states and OSW developers to develop the workforce and suggests that this potential constraint is beginning to be addressed.
Some final questions:
Our initial analysis indicates that the critical pinch points are being addressed. However, how do all these programs and investment fit together?
Is there unnecessary overlap or areas where additional investment will provide the greatest benefit in terms of avoiding supply constraints and facilitating the desired development of the OSW supply chain in the US?
Have you submitted an Application for Qualification for a generation project in the ongoing NYSERDA Renewable Energy Standard RFP (RESRFP19-1) or are otherwise looking to advance your renewable project development efforts in New York?
Power Advisory offers a full suite of New York market forecasts and strategy consulting services to support these development efforts. Our services include the essentials to forecast project revenues, understand the major risks and opportunities associated with participating in the New York markets and submitting competitive proposals. Power Advisory’s New York market offerings include:
– Electricity Price Forecast (considering zonal and technology weighted NYISO energy revenues) – Capacity Price Forecast (focused on the NYISO spot auctions and locational differences) – NYSERDA Tier 1 REC Forecast (by contract year for the anticipated schedule of RES RFPs) – Carbon Pricing Proposal Analysis (considering the implementation of carbon pricing in the NYISO energy markets) – Policy & Market Backgrounders (covering the key policies and market structures that shape NY generation development) – Proposal Drafting/Strategy (direct support of bid preparation and strategies to maximize your chances for contract award) – Registration/Participation Support (for NYGATS and the NYISO administered markets)
We supported successful proponents in the last NYSERDA solicitation, RESRFP18-1, resulting in executed long-term fixed price REC contracts for our clients. 19 projects totaling 1,364 MW of solar, wind and energy storage were contracted in the 2018 solicitation. The weighted average REC price was $18.52. Since then, New York has upped its renewable and clean energy commitments with targets of 70% renewables by 2030 and 100% carbon-free electricity by 2040 and there have been other significant market changes.
Power Advisory specializes in electricity market analysis and strategy, power procurement, policy development, regulatory and litigation support, market design and project feasibility assessment. Our team has completed work in each of the North American electricity markets including numerous consulting projects in New York State. Power Advisory’s understanding of wholesale electricity markets, energy policy, resource procurement and renewable technologies makes us well qualified to support your generation development efforts.
Since Janet
Mills was sworn in as governor in January and the democrats had also secured
control of both chambers, the expectation was that 2019 was going to be a big
year for climate and clean energy in Maine. This has certainly turned out to be
true. As an early action, Governor Mills issued Executive Order 3 FY 19/20 to conclude the Maine Wind Advisory Commission
and wind permit moratorium that had been in place since the beginning of 2018. A
flurry of legislation was also introduced addressing everything from net
metering (re-instituted in March through L.D. 91) to electrification, the renewable
portfolio standard, procurement targets and Aqua Ventus floating offshore wind
pilot project.
Leading up to
the adjournment of the legislative session on June 20th a number of these
bills passed and were subsequently signed by the Governor. Most notable to renewable
generation development in the state were L.D. 1494 and L.D. 1711, which are
reviewed below. These offer direct opportunities for long-term contracts for
new projects. Respectively, about 400-800 MW of utility scale renewables and 375
MW of distributed solar by 2024.
L.D. 1494 passed the legislature on
June 18th, 2019 and was signed into law by the Governor the
following week. It expands Maine’s RPS to 80% by 2030 and to 100% by 2050 from
40% (Class I – New 10% and Class II – Existing Resources 30%) while creating a
new class of RPS resources, Class IA, for the incremental renewable generation
capacity targeted.
In addition,
it calls for the competitive
procurement of Class IA resources to the level of 14% of 2018 state retail electricity
sales, about 1,500 GWh, through a series of two RFPs to be issued by 2021.
Energy storage, mechanical, chemical or thermal, can be awarded contracts if paired
with eligible Class IA resources. The first RFP is likely to be issued in late
2019 or early 2020 for approximately 750-1,100 GWh (7-10% of 2018 sales
per the legislation). A second RFP will then be issued in late
2020 but no later than Jan 15th, 2021 for 450-750 GWh (14% of
2018 electricity sales minus the generation contracted in the first RFP).
The Maine Public Utilities Commission is responsible for administering the reformed RPS including the two mandated procurements. In this role, the Commission is to direct the Maine investor-owned transmission and distribution utilities to enter the long-term contracts selected from the RFPs. The state’s two investor owned utilities are Avangrid’s Central Maine Power (CMP) and Emera Maine (Bangor Hydro Electric Co. and Maine Public Service Co.), which is pending sale to ENMAX Corporation. While the Commission will retain significant discretion in the solicitations certain aspects were directed in L.D. 1494.
Overall the estimated near term opportunity
resulting from the reformed Maine RPS is 400 MW of land based wind, 850 MW solar or a combination
of the two technologies.This opportunity for new renewable generation
resources could be up to 25% lower to the extent that sufficient resources that
began commercial operations on or prior to June 30, 2019 are available.
An Act To Promote Solar Energy Projects and
Distributed Generation Resources in Maine (L.D. 1711 / Chapter 478 PL)
L.D. 1711 calls for the competitive procurement
of distributed generation (DG) resources in sequential blocks for a total of 125
MW commercial or institutional DG (i.e. non-residential customers) and 250 MW
of community shared DG by July 1, 2024. The initial procurement must occur on
or before July 1, 2020 with the rules for both solicitations to be in place by
January. Four additional blocks of DG are then to be used by the PUC to meet
the overall procurement goals with stipulations on each block that the contract
rate be equal to 97% of the preceding block. For the purposes of these
procurements a DG resource means an electric generating facility with a
nameplate capacity less than 5 MW that uses an eligible renewable fuel or
technology and is located in the service territory of a Maine T&D utility. Solar
is understood to be the predominant distributed renewable technology.
There are number of specifics in this law with regards to the competitive procurements and net energy billing which should be reviewed. An earlier version included a 400 MW utility-scale procurement provision with a $35/MWh cap, but that was struck from the enacted version.
Carson Robers, Senior Consultant, Power Advisory LLC
This memo
updates our review of the New Jersey Board of Public
Utilities (BPU) Offshore Wind Renewable Energy Certificates (OREC) award to
Ørsted US Offshore Wind’s 1,100 MW Ocean Wind project. The BPU made available
its order and this
provided additional details, which required that our earlier memo be updated. In
this memo, we focus on the Ocean Wind contract pricing.
The Ocean Wind project will be developed in three tranches of 368 MW each with a COD in 2024. The first year all-in OREC price is $98.10 per MWh and this price is realized only by Phase 1 for one-month after which it escalates. The price escalates at 2% per year such that in 2045 the contract price will be $148.68/MWh. This equates to a nominal levelized price of $116.82/MWh, representing a 19% premium relative to the price for the smaller Revolution Wind project secured by Rhode Island, which has a similar COD in 2024. The premium is considerably greater relative to the contract price for the Vineyard Wind project, which is able to realize a higher investment tax credit.
Nominal Levelized Pricing Comparison ($/MWh)
Frankly, we are surprised by the magnitude of this premium, even
with the superior wind resource that is available to the Revolution Wind
project. Interestingly, the OREC Order provides for an annual OREC allowance,
which implies a 50%, capacity factor which is higher than that reported for
Revolution Wind. However, Ocean Wind is precluded from selling more ORECs than
its annual allowance, so this allowance is likely to be greater than a P50
estimate.
The lack of transparency regarding the evaluation and scoring
framework used by the BPU doesn’t help in explaining this outcome. The BPU evaluation
criteria were identified as the OREC purchase price, economic impact, ratepayer
impact, environmental impact, the strength of guarantees for economic impact,
and the likelihood of successful commercial operation. However, the relative
weights of these evaluation criteria aren’t specified and the tradeoffs that
the BPU made in selecting Ocean Wind cannot be ascertained.
Nonetheless, it does appear that there were tradeoffs with respect to these evaluation criteria. Specifically, the BPU order indicates that the Ocean Wind project “provides the best economic development benefits to the state of any of the applicants.” Further, it notes that “Although other projects presented a lower PVNOC [Present Value of Net OREC Cost], given the Ocean Wind 1,100 MW project’s strength in all of the other evaluation criteria, an award to Ocean Wind is in the best interest of the State of New Jersey and its ratepayers” (BPU Order, p. 19).
