The U.S.’ first commercial forays into offshore wind could soon dot the horizon off New England’s Atlantic Coast. Two projects totaling nearly 500 MW (Cape Wind in Massachusetts and Block Island in Rhode Island) are expected to start delivering offshore wind power as early as 2017.
With this in mind, concerns have been raised regarding how offshore wind development will impact renewable energy credit (REC) markets.
Prices for premium New England Class I RECs have already fallen almost 20% over the last six months. These price movements have had little to do with offshore wind, but there is speculation that additional supply from such projects could drive the market long in 2017 and crash prices.
Without offshore wind, NEPOOL REC prices should correct themselves automatically. The circular logic of REC market fundamentals would have low REC pricing jeopardizing future development. As renewable energy project profit margins get squeezed, fewer projects will be built and forward REC prices would rebound as forward supply tightens.
The worry is that offshore wind projects could break this self-correcting market logic in the New England Power Pool (NEPOOL).
The Cape Wind and Block Island projects have already contracted off-take agreements with major utilities, such as National Grid and NStar. Regardless of depressed REC prices in the interim, the projects are expected to be fully operational and supplying up to 10% of aggregate NEPOOL Class I REC demand by 2017. Both are currently in advanced stages of development and could be the first operational projects in the U.S.
To understand how sensitive future REC pricing will be to the addition of offshore wind RECs, it is important to understand the underlying onshore supply and demand dynamic.
For New England Class I RECs, the last few years have been broadly characterized by undersupply. As a result, REC pricing has remained near the relevant alternative compliance payments (ACPs) for each state. ACPs represent the penalty rates that electricity suppliers that don’t procure enough RECs to meet their compliance obligations must pay. Pricing has fallen away from these ACPs over the last few months, though, as suppliers have priced in more adequate forward supply to meet their renewable portfolio standard (RPS) requirements. Their expectations are based on shrinking Massachusetts forward demand, increasing aggregate qualified supply and a robust development pipeline.
Shrinking forward Massachusetts demand impacts REC prices across NEPOOL. Boasting an elevated ACP and the largest, most liquid NEPOOL market, Massachusetts has historically maintained the highest REC prices in the region. The state’s premium has been eroded of late, however, and its REC prices have converged with that of Connecticut.
This has, in part, happened because the Massachusetts solar carve-out is increasing by 140% in 2015. Effective Massachusetts demand for non-solar Class I RECs will then be reduced by over 200,000 RECs. As supply competes to find buyers, prices will fall and RECs will flow to other NEPOOL states, filling aggregate demand.
There are two important potential regulatory changes that could lend price support to Class I RECs by reducing available supply – namely the expiration of the production tax credit (PTC) and the disqualification of Vermont REC eligibility from other NEPOOL state RPS markets.
If pipeline projects relying on the PTC are mothballed because the incentive is not extended, a very significant amount of potential supply could be prevented from making it to market.
Similarly, if current rulemaking in Connecticut concludes by disqualifying Vermont RECs from satisfying Connecticut RPS obligations, then other NEPOOL states could follow suit and all Vermont RECs supply would effectively be removed from the NEPOOL market.
The aggregate impact of reduced supply as a result of these two potential developments would far outweigh the combined addition of supply from Cape Wind and Block Island.
What is critical to recognize is that these two projects only represent a fraction of the offshore wind capacity that could come online in the future. Although there is no U.S. offshore wind capacity installed currently, there are more than 7 GW installed globally. Moreover, there are 14 projects totaling 4.9 GW in the U.S. that are already in advanced stages of development and expected to reach commercial operations within the decade.
The vast majority of this potential U.S. capacity is located off the Atlantic Coast. The real long-term concern for REC markets then relates to how much of this capacity actually comes online and how quickly it does so.
Getting the full 4.9 GW to the finish line will not be easy. Offshore wind is just starting to move down its experience curve in the U.S. and, therefore, is still expensive. The Cape Wind and Block Island project’s contracts are for $187/MWh and $244/MWh, respectively, each with 3.5% annual escalators. This can be compared with onshore wind projects, which can be profitable delivering power anywhere between $45/MWh and $85/MWh (on an unsubsidized basis).
Contracts for future offshore wind projects will likely be more cost-competitive than these initial two. The enormous first-mover hurdles that these pioneering U.S. projects have had to overcome have driven their price premium.
Cape Wind, for instance, has been in the works since 2001. Future projects will benefit not just from lower capital costs, but also from the U.S. Department of the Interior’s Smart from the Start Initiative, which is specifically designed to reduce offshore wind development costs by streamlining siting, leasing, permitting and construction.
In sum, even if the Cape Wind and Block Island projects come online as expected, they are not likely by themselves to crash the NEPOOL market by 2017. They will provide up to 10% of demand, though, and depending on the interplay between other moving pieces in onshore development and regulations, they could move market pricing and deserve attention.
More importantly for the long-term outlook of NEPOOL Class I RECs will be additional offshore wind development beyond these initial two projects. Compelling characteristics – such as the ability to site near load pockets where alternative onshore options are limited, strong capacity factors and consistent production profiles – make such projects desirable.
Ultimately, offshore wind costs still need to come down, but if they do and if installations pick up on the heels of successful interconnections for Cape Wind and Block Island, then RPS demand will be hard pressed to keep up with increasing supply in the long term.
Jason Prince is research director at Karbone, a financial services firm covering energy and environmental markets.
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