Canada's highest court has ruled that Quebec's provincial utility Hydro-Quebec cannot be required to renegotiate a long-term contract to buy power from a Labrador hydroelectric plant at below-market rates, even though the deal has yielded about 14 times more profit for Hydro-Quebec than for the Labrador generator.
At issue is the Churchill Falls hydroelectric plant on the upper Churchill River in Labrador, and a 1969 agreement between Hydro-Quebec and Churchill Falls (Labrador) Corporation Limited -- a company jointly owned by Newfoundland and Labrador Hydro and Hydro-Quebec. The Churchill Falls plant can generate 5,428 megawatts of power, and is one of the world's largest hydroelectric power stations.
According
to former Premier of Newfoundland and Labrador Brian Tobin,
during pre-construction negotiations, Hydro-Quebec told Churchill Falls that it would not allow the Labrador generator to "wheel" project
power through the Hydro-Quebec grid, nor to build its own power line through Quebec to
reach U.S. markets. As a result, under the terms of the 1969 agreement, Hydro-Quebec agreed to buy most of the project's power at the fixed price of $2.50 per megawatt-hour, to guarantee construction cost overruns, and to build transmission lines connecting the generators to markets, enabling the Labrador generator to sell power and to use debt financing to construct the plant. The original contract was set to expire in 2016, but included a renewal
clause allowing Hydro-Quebec to extend the contract for an additional 25
years at a fixed price of $2 per megawatt-hour through 2041.
After the contract was signed, changes in the electricity market -- including oil price shocks in the 1970s, a decline in public confidence in nuclear power after a 1979 accident, and the U.S. Federal Energy Regulatory Commission's 1996 decision to require open access to transmission systems -- meant the contract's purchase price is now well below market prices. Because Hydro-Quebec sells electricity from the plant to third parties
at market prices, Hydro-Quebec reaps substantial profits from the deal. For example, Hydro-Quebec reports that the average retail price for residential customers in St. John's, Newfoundland in 2018 is $120.30 per megawatt-hour. Canada's National Energy Board says the 2017 average wholesale prices for electricity imports were over $24 per megawatt-hour, with exports priced even higher at $38.58 per megawatt-hour -- over 19 times higher than the price Hydro-Quebec now pays Churchill Falls during the extended contract term. According to CBC, the contract has yielded about $28 billion in profits to Quebec, but just $2 billion for Newfoundland and Labrador.
Citing legal theories including a general duty of good faith, Nalcor Energy subsidiary Churchill Falls asked Canadian courts to order that the contract be renegotiated and the benefits be reallocated. After lower courts sided with Hydro-Quebec, the generator appealed to the Supreme Court of Canada.
On November 2, the Supreme Court of Canada rendered its judgment in the matter of Churchill Falls (Labrador) v. Hydro-Quebec. The high court found, by a 7 to 1 decision, for Hydro-Quebec, noting that the parties "bound themselves knowing full well what they were doing" and that Hydro-Quebec could insist on adhering to the contract despite the "unforeseen" increase in the power's market value.
The one dissenting judge characterized the contract as "relational" in nature, and thus said that both parties are subject to a duty of cooperation which Hydro-Quebec breached by failing to renegotiate and to more fully share the benefits of higher-than-expected market prices. He said that because "a profit imbalance of this nature and magnitude is beyond what the parties intended when they concluded the agreement", the parties had an implied obligation to cooperate in establishing a mechanism for the allocation of "extraordinary profits."
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Showing posts with label long-term contract. Show all posts
Showing posts with label long-term contract. Show all posts
NH SEC denies Northern Pass certificate
Thursday, February 1, 2018
The New Hampshire Site Evaluation Committee has unanimously voted to deny an application to develop a major new electric transmission line across that state, according to an article in the Union Leader. According to that article, the Committee felt the Northern Pass Transmission developer had not satisfied its burden under state law to show that the line's development would not
“unduly interfere with the orderly development of the region.”
Northern Pass Transmission, LLC has proposed a 192-mile transmission line project capable of bringing 1,090 megawatts of power into New England. The project includes a new direct current (DC) transmission line from the Canadian border to a new converter terminal to be built in Franklin, New Hampshire, as well as a new AC transmission line connecting to the existing grid at a substation in Deerfield.
To develop the project, the developer needs approval from the New Hampshire Site Evaluation Committee in the form of a Certificate of Site and Facility. Northern Pass applied to the SEC for a certificate in 2015; the case before the Committee has been ongoing since then, with extensive testimony and hearings held last month.
Successful project development involves not just securing all required permits, but also finding or creating suitable commercial arrangements. While the project's siting application was pending, the project won some commercial success last week, when a group of Massachusetts utilities seeking to jointly procure clean electricity selected a Northern Pass-affiliated proposal to supply about 9,450,000 megawatt-hours per year from Canada. After reviewing over 40 bids, the bid committee selected the "Northern Pass Transmission, Hydro" option for negotiation of a final long-term power sales agreement under the state's Section 83D clean energy contracting program.
Today's decision by the New Hampshire Site Evaluation Committee relates directly to siting, not to commercial matters. The developer may be able to challenge the Committee's permitting decision. In the meantime, could the SEC decision affect the Northern Pass project's commercial fate? According to the Massachusetts 83D website, "If the bid selected to advance to contract negotiation at this stage does not successfully negotiate contracts, it may result in other bid(s) being selected to advance to contract negotiations." If the lack of SEC approval (for now) means Northern Pass does not successfully negotiate contracts with the Massachusetts utilities, it could open the door for other 83D bidders to move forward.
Northern Pass Transmission, LLC has proposed a 192-mile transmission line project capable of bringing 1,090 megawatts of power into New England. The project includes a new direct current (DC) transmission line from the Canadian border to a new converter terminal to be built in Franklin, New Hampshire, as well as a new AC transmission line connecting to the existing grid at a substation in Deerfield.
To develop the project, the developer needs approval from the New Hampshire Site Evaluation Committee in the form of a Certificate of Site and Facility. Northern Pass applied to the SEC for a certificate in 2015; the case before the Committee has been ongoing since then, with extensive testimony and hearings held last month.
Successful project development involves not just securing all required permits, but also finding or creating suitable commercial arrangements. While the project's siting application was pending, the project won some commercial success last week, when a group of Massachusetts utilities seeking to jointly procure clean electricity selected a Northern Pass-affiliated proposal to supply about 9,450,000 megawatt-hours per year from Canada. After reviewing over 40 bids, the bid committee selected the "Northern Pass Transmission, Hydro" option for negotiation of a final long-term power sales agreement under the state's Section 83D clean energy contracting program.
Today's decision by the New Hampshire Site Evaluation Committee relates directly to siting, not to commercial matters. The developer may be able to challenge the Committee's permitting decision. In the meantime, could the SEC decision affect the Northern Pass project's commercial fate? According to the Massachusetts 83D website, "If the bid selected to advance to contract negotiation at this stage does not successfully negotiate contracts, it may result in other bid(s) being selected to advance to contract negotiations." If the lack of SEC approval (for now) means Northern Pass does not successfully negotiate contracts with the Massachusetts utilities, it could open the door for other 83D bidders to move forward.
Maine community solar procurement bill, LD 1444
Wednesday, April 26, 2017
This week a committee of the Maine state legislature is scheduled to hold a public hearing on a bill that would direct state regulators to enter into long-term contracts to procure 120 megawatts of large-scale community solar distributed generation resources by 2022. While Maine law currently allows some community-scale solar development, LD 1444, An Act Regarding Large-scale Community Solar Procurement, would create new structures geared toward state-sponsored long-term contracts and could open the door to broader ownership of or participation in community-scale solar in Maine.
If enacted into law as drafted, the bill would direct the Maine Public Utilities Commission to hold a series of four annual competitive solicitations by January 1, 2022. Each solicitation would seek to procure 30 megawatts of large-scale community solar distributed generation resources.
Through an initial solicitation to be held by March 1, 2018, the Commission would set a uniform clearing price or "standard solar rate" for all awarded bids in the initial procurement. Subsequent procurements would be subject to a declining block contract rate, under which the Commission would reduce the rate relative to the previous procurement by up to 3%. But if the Commission were to conclude that a subsequent solicitation was not competitive, no bidders may be selected and the capacity available in that solicitation will be deferred to a subsequent solicitation.
Any resource selected for contracting would be offered a standard contract for a term of 20 years at the specified contract rate. The resources' counterparty would be a "standard buyer" whose mission would be to "aggregate the output of the portfolio of distributed generation resources procured pursuant to this chapter and sell or use the output of these resources in a manner that maximizes the value of this portfolio of resources to all ratepayers." Initially, the bill designates each investor-owned transmission and distribution utility as the standard buyer for its own service territory, but it would allow the Commission to designate another entity if doing so is in the best interest of ratepayers. The benefits and costs of the procurement, shall be tracked and reviewed annually, and any gains would be allocated to from ratepayers of the project's host utility -- just as any losses would be recovered from those ratepayers.
On the project side, LD 1444 would establish a sponsor/subscriber model for large-scale community solar distributed generation resources. A project sponsor would own or operate the resource. A customer could subscribe for a proportional interest in such a resource, sized to represent at least one kilowatt of the resource's generating capacity. Several additional requirements include:
LD 1444 is scheduled for a public hearing before the Committee on Energy, Utilities and Technology on April 27, 2017.
If enacted into law as drafted, the bill would direct the Maine Public Utilities Commission to hold a series of four annual competitive solicitations by January 1, 2022. Each solicitation would seek to procure 30 megawatts of large-scale community solar distributed generation resources.
Through an initial solicitation to be held by March 1, 2018, the Commission would set a uniform clearing price or "standard solar rate" for all awarded bids in the initial procurement. Subsequent procurements would be subject to a declining block contract rate, under which the Commission would reduce the rate relative to the previous procurement by up to 3%. But if the Commission were to conclude that a subsequent solicitation was not competitive, no bidders may be selected and the capacity available in that solicitation will be deferred to a subsequent solicitation.
Any resource selected for contracting would be offered a standard contract for a term of 20 years at the specified contract rate. The resources' counterparty would be a "standard buyer" whose mission would be to "aggregate the output of the portfolio of distributed generation resources procured pursuant to this chapter and sell or use the output of these resources in a manner that maximizes the value of this portfolio of resources to all ratepayers." Initially, the bill designates each investor-owned transmission and distribution utility as the standard buyer for its own service territory, but it would allow the Commission to designate another entity if doing so is in the best interest of ratepayers. The benefits and costs of the procurement, shall be tracked and reviewed annually, and any gains would be allocated to from ratepayers of the project's host utility -- just as any losses would be recovered from those ratepayers.
On the project side, LD 1444 would establish a sponsor/subscriber model for large-scale community solar distributed generation resources. A project sponsor would own or operate the resource. A customer could subscribe for a proportional interest in such a resource, sized to represent at least one kilowatt of the resource's generating capacity. Several additional requirements include:
- The total expected annual value of all of a customer's subscriptions must not exceed 120% of the customer's most recent annual electricity bill.
- At least 50% of the subscriptions to a large-scale community solar distributed generation resource must be for 25 kilowatts or less, unless a municipality accounts for more than 50% of the subscriptions to a large-scale community solar distributed generation resource.
- A municipality may not account for more than 70% of the subscriptions to a large-scale community solar distributed generation resource.
LD 1444 is scheduled for a public hearing before the Committee on Energy, Utilities and Technology on April 27, 2017.
Maine biomass procurement competitive standards
Thursday, May 19, 2016
As the Maine Public Utilities Commission prepares for its upcoming procurement of biomass power resources, the Commission has requested public comment on the standards and criteria to be used in evaluating whether the solicitation is "not competitive."
This spring, the Maine State Legislature enacted An Act To Establish a Process for the Procurement of Biomass Resources. The law directs the Maine Public Utilities Commission to initiate a competitive solicitation as soon as practicable, seeking proposals for 2-year contracts for up to 80 megawatts of biomass resources.
But largely due to fairness and cost-containment concerns, the legislature created a "safety valve" in case the solicitation turns out to be "not competitive." The Act specifies that “If the commission concludes that the solicitation ... is not competitive, no bidders may be selected and the commission is not obligated to enter into a contract.”
On May 17, 2016, the Commission issued a request for comment in its Procurement of Biomass Resources docket. That request describes the Commission's plans to initiate the procurement process "in the near future" through the issuance of a request for proposals or RFP. But before issuing the RFP, the Commission has requested comment on the standards and criteria to be used to determine whether the solicitation is “not competitive” pursuant to the Act.
Comments are requested by May 30, 2016.
This spring, the Maine State Legislature enacted An Act To Establish a Process for the Procurement of Biomass Resources. The law directs the Maine Public Utilities Commission to initiate a competitive solicitation as soon as practicable, seeking proposals for 2-year contracts for up to 80 megawatts of biomass resources.
But largely due to fairness and cost-containment concerns, the legislature created a "safety valve" in case the solicitation turns out to be "not competitive." The Act specifies that “If the commission concludes that the solicitation ... is not competitive, no bidders may be selected and the commission is not obligated to enter into a contract.”
On May 17, 2016, the Commission issued a request for comment in its Procurement of Biomass Resources docket. That request describes the Commission's plans to initiate the procurement process "in the near future" through the issuance of a request for proposals or RFP. But before issuing the RFP, the Commission has requested comment on the standards and criteria to be used to determine whether the solicitation is “not competitive” pursuant to the Act.
Comments are requested by May 30, 2016.
Maine community renewable energy project winds down
Monday, December 14, 2015
Maine energy regulators will soon act on proposals for community-based renewable energy projects, as legal authority for a community energy pilot program winds down.
In 2009, the Maine Legislature enacted An Act To Establish the Community-based Renewable Energy Pilot Program, P.L. 2009, ch. 329. The Act established a pilot program to provide incentives for the development of community-based renewable projects. To qualify, projects must be “locally owned electricity generating facilities” (51% or more of the facility must be owned by “qualifying local owners”) and must not exceed 10 MW. The Maine Public Utilities Commission was charged with administering the program, including certifying qualifying facilities. To a community renewable energy project developer, the program offered the opportunity to win a long-term contract to sell project power to a Maine utility at predictable prices.
A 2015 law amended the community-based renewable energy program. Among other changes, it required the Commission to perform a "viability assessment" of all projects that have been certified under the program but have not yet reached commercial operations. For any projects the Commission determines will not be viable by December 31, 2018, the Act states that the Commission must revoke any contract awarded, though the projects will remain certified. In September 2015, the Commission completed its viability assessment and identified approximately 21 megawatts of capacity that is available for contract awards.
The 2015 law effectively provides that the Commission's authority to order utilities to enter into community-based renewable energy projects expires on December 31, 2015. In light of the 21 megawatts of program capacity identified as available, on September 30, the Commission issued a request for proposals for projects seeking the remaining contract awards.
Proposals were due by November 6, 2015. According to the RFP, the Commission will complete its evaluation of proposals and accept or reject proposals no later than December 31.
In 2009, the Maine Legislature enacted An Act To Establish the Community-based Renewable Energy Pilot Program, P.L. 2009, ch. 329. The Act established a pilot program to provide incentives for the development of community-based renewable projects. To qualify, projects must be “locally owned electricity generating facilities” (51% or more of the facility must be owned by “qualifying local owners”) and must not exceed 10 MW. The Maine Public Utilities Commission was charged with administering the program, including certifying qualifying facilities. To a community renewable energy project developer, the program offered the opportunity to win a long-term contract to sell project power to a Maine utility at predictable prices.
A 2015 law amended the community-based renewable energy program. Among other changes, it required the Commission to perform a "viability assessment" of all projects that have been certified under the program but have not yet reached commercial operations. For any projects the Commission determines will not be viable by December 31, 2018, the Act states that the Commission must revoke any contract awarded, though the projects will remain certified. In September 2015, the Commission completed its viability assessment and identified approximately 21 megawatts of capacity that is available for contract awards.
The 2015 law effectively provides that the Commission's authority to order utilities to enter into community-based renewable energy projects expires on December 31, 2015. In light of the 21 megawatts of program capacity identified as available, on September 30, the Commission issued a request for proposals for projects seeking the remaining contract awards.
Proposals were due by November 6, 2015. According to the RFP, the Commission will complete its evaluation of proposals and accept or reject proposals no later than December 31.
Maine PUC considers community energy projects
Thursday, September 17, 2015
The Maine Public Utilities Commission is evaluating the viability of proposed community-based renewable energy projects that remain under development.
Maine has run a community-based renewable energy program since 2009. The program gives qualified wind, solar, and other renewable energy projects long-term contracting opportunities to sell the facility’s output to a Maine transmission and distribution utility at attractive rates.
In 2015, the Maine Legislature adopted P.L. 2015 ch. 232, An Act to Amend the Community-based Renewable Energy Program”. Beyond minor revisions to the law, the act adds strict deadlines for key program milestones: the Public Utilities Commission has until December 31, 2015 to order or allow utilities to enter into long-term contracts under the program, and all projects selected for a contract must become operational and commence generating electricity by December 31, 2018.
Section 5 of the Act also created a new "viability assessment" process designed to make sure the program is as effective as possible. The program size is capped at 50 megawatts statewide; all of this capacity was quickly claimed by certified projects. But not all projects that have been certified are operational; some have yet to be built. Some stakeholders expressed concern over "permit banking" -- developers obtaining and holding onto program capacity, without actively developing it, while other projects would move forward if they could get the capacity.
As a result, the Legislature directed the Commission to review all certified projects that have not yet reached commercial operations, to determine whether the projects are reasonably likely to achieve commercial operations within a 3-year period. If the Commission determines a project will not be viable by December 31, 2018, the Act directs the Commission to revoke any contract awarded, but such projects will remain certified under the program. If the removal of nonviable projects frees up program capacity for contracting, the law directs the Commission to conduct an expedited request for proposals to select community-based renewable energy projects to become program participants and enter into long-term contracts.
The Commission's viability assessment process is now ongoing. A July 13, 2015 procedural order identified six projects as having been either certified or awarded a contract, but not been placed in commercial operation. Project developers were invited to submit information related to the viability assessment by August 7.
The Commission meets on September 22 to deliberate on the viability assessments.
Maine has run a community-based renewable energy program since 2009. The program gives qualified wind, solar, and other renewable energy projects long-term contracting opportunities to sell the facility’s output to a Maine transmission and distribution utility at attractive rates.
In 2015, the Maine Legislature adopted P.L. 2015 ch. 232, An Act to Amend the Community-based Renewable Energy Program”. Beyond minor revisions to the law, the act adds strict deadlines for key program milestones: the Public Utilities Commission has until December 31, 2015 to order or allow utilities to enter into long-term contracts under the program, and all projects selected for a contract must become operational and commence generating electricity by December 31, 2018.
Section 5 of the Act also created a new "viability assessment" process designed to make sure the program is as effective as possible. The program size is capped at 50 megawatts statewide; all of this capacity was quickly claimed by certified projects. But not all projects that have been certified are operational; some have yet to be built. Some stakeholders expressed concern over "permit banking" -- developers obtaining and holding onto program capacity, without actively developing it, while other projects would move forward if they could get the capacity.
As a result, the Legislature directed the Commission to review all certified projects that have not yet reached commercial operations, to determine whether the projects are reasonably likely to achieve commercial operations within a 3-year period. If the Commission determines a project will not be viable by December 31, 2018, the Act directs the Commission to revoke any contract awarded, but such projects will remain certified under the program. If the removal of nonviable projects frees up program capacity for contracting, the law directs the Commission to conduct an expedited request for proposals to select community-based renewable energy projects to become program participants and enter into long-term contracts.
The Commission's viability assessment process is now ongoing. A July 13, 2015 procedural order identified six projects as having been either certified or awarded a contract, but not been placed in commercial operation. Project developers were invited to submit information related to the viability assessment by August 7.
The Commission meets on September 22 to deliberate on the viability assessments.
Maine long-term contracting for electricity
Tuesday, April 7, 2015
Maine energy regulators have asked for public comment on the goals and objectives for a decade-old program supporting long-term contracts between utilities and independent power producers. At stake is the future of Maine's long-term contracting program for electricity resources.
In 2006, the Maine State Legislature enacted an Act to Enhance Maine’s Energy Independence and Security, P.L. 2005, ch. 677. Part C of that Act (codified at 35-A M.R.S. § 3210-C) authorizes the Maine Public Utilities Commission to direct transmission and distribution utilities to enter into long-term contracts for capacity and energy. The statute directs the Commission to conduct a competitive solicitation for contracts at least every three years, and specifies the framework that the Commission must use in selectingcapacity resources for contracting, including a stated priority list of types of resources and a duty to select lowest price offers.
Since the Act's enactment, the Commission has conducted five solicitations under this program (including the current solicitation, under which proposals are due by May 1, 2015). In each case, the Commission has hired an outside consultant to forecast relevant markets for energy, capacity, and renewable energy credits to be used in evaluating the value of the market products offered in responsive bids.
Today, the Commission issued a Notice of Inquiry into the goals and objectives for long-term contracting under the Act. In the notice, the Commission asks for public comment on how long-term contracts can most effectively be used to support the development of increased generation from renewable resources, and reduce price volatility and greenhouse gas emissions; how the Commission should evaluate proposals' price reduction benefits; and how to best structure transactions.
The Commission also asked for comment on relatively novel potential uses of the program, including leveraging federal support for energy programs to benefit Maine ratepayers, increasing in-state generation capacity such that Maine would “separate” from the rest of New England in the regional forward capacity market to yield reduced in-state prices for capacity, and "geo-targeting" capacity resources to avoid transmission and distribution costs more effectively.
Finally, the Commission requested feedback on its long-term contracting process. Should the Commission issue requests for proposal on a set schedule (e.g. every two years), or should it retain discretion as to when to issue an RFP? Should the process include fixed dates for key milestones like submission of final bids or Commission decisions, or should it remain flexible and unfixed?
Comments are due to the Maine Public Utilities Commission by May 6, 2015.
In 2006, the Maine State Legislature enacted an Act to Enhance Maine’s Energy Independence and Security, P.L. 2005, ch. 677. Part C of that Act (codified at 35-A M.R.S. § 3210-C) authorizes the Maine Public Utilities Commission to direct transmission and distribution utilities to enter into long-term contracts for capacity and energy. The statute directs the Commission to conduct a competitive solicitation for contracts at least every three years, and specifies the framework that the Commission must use in selectingcapacity resources for contracting, including a stated priority list of types of resources and a duty to select lowest price offers.
Since the Act's enactment, the Commission has conducted five solicitations under this program (including the current solicitation, under which proposals are due by May 1, 2015). In each case, the Commission has hired an outside consultant to forecast relevant markets for energy, capacity, and renewable energy credits to be used in evaluating the value of the market products offered in responsive bids.
Today, the Commission issued a Notice of Inquiry into the goals and objectives for long-term contracting under the Act. In the notice, the Commission asks for public comment on how long-term contracts can most effectively be used to support the development of increased generation from renewable resources, and reduce price volatility and greenhouse gas emissions; how the Commission should evaluate proposals' price reduction benefits; and how to best structure transactions.
The Commission also asked for comment on relatively novel potential uses of the program, including leveraging federal support for energy programs to benefit Maine ratepayers, increasing in-state generation capacity such that Maine would “separate” from the rest of New England in the regional forward capacity market to yield reduced in-state prices for capacity, and "geo-targeting" capacity resources to avoid transmission and distribution costs more effectively.
Finally, the Commission requested feedback on its long-term contracting process. Should the Commission issue requests for proposal on a set schedule (e.g. every two years), or should it retain discretion as to when to issue an RFP? Should the process include fixed dates for key milestones like submission of final bids or Commission decisions, or should it remain flexible and unfixed?
Comments are due to the Maine Public Utilities Commission by May 6, 2015.
Solar bonds: SolarCity launches first US public debt offering
Wednesday, October 15, 2014
Could publicly offered solar bonds play a significant role in financing solar photovoltaic projects?
Solar energy company SolarCity Corporation appears to think so, as this morning it filed a registration statement with the U.S. Securities and Exchange Commission to issue up to $200 million in solar bonds. SolarCity describes the move as "the nation’s first registered public offering of solar bonds." What does SolarCity's solar bond offering mean for solar energy?
By some metrics, SolarCity is the largest developer of residential solar photovoltaic projects in the U.S. The company says it is currently providing more than one out of every three new solar power systems in the U.S., and notes that it "installed more residential solar in the second quarter of 2014 than its next 50 competitors combined." While SolarCity develops projects under several financial models, its typically installs rooftop solar panels at its customers' sites with no upfront costs to the customer, who then pays the company every month for leasing the facilities or for the electricity it uses. These long-term contracts create more stable ongoing revenues for SolarCity compared to those experienced by developers of turnkey projects who may end their relationship after the project is commissioned.
SolarCity's model has proved attractive to capital, as it has been involved with financing the installation of approximately $5 billion in renewable energy assets. Much of the capital SolarCity needs to develop these projects has come from investments from major banks and corporations including US Bancorp and Google Inc., as well as individuals owning shares of the company's stock (traded as SCTY).
SolarCity has also turned to debt offerings, making three private placements of solar bonds in the last year. Generally speaking, SolarCity will pay returns on the bonds using income generated from customers' monthly payments. Because this income stream is both relatively stable and predictable, it should enable repayment of the bonds plus a steady yield.
But no company has previously publicly offered solar bonds of this type in the U.S. SolarCity thus views its publicly offered solar bonding model as unique, in that it gives individual investors access to new investment opportunities -- and in turn, it may give SolarCity access to a whole lot more money -- up to $200 million in this round, with the prospect of more to come.
Under SolarCity's new offering, investors will be able to purchase solar bonds for as little as $1,000, with maturities ranging from one year to seven years and interest rates of up to 4 percent. The relatively short maturity of these bonds, compared to those previously offered to institutional investors, helps reduce the risk that during the bonds' lives utility rates will change in a way that hurts their economics.
The company notes that solar bonds will be available to all U.S. investors who are at least 18 years old and meet SolarCity’s eligibility requirements, with no fees for purchase. Indeed, the relatively low $1,000 minimum investment for this solar bond offering highlights SolarCity's strategy of targeting the millions of small or "retail" investors. To facilitate these individual investors' access to the bonds, the company launched a new online investment site (solarbonds.solarcity.com).
How will the new solar bond offering affect SolarCity and the pace of solar development in the US? With a market capitalization of $4.2 billion, SolarCity is relatively large compared to the $200 million that it may raise pursuant to the current public bond offering. Nevertheless, individual investors' appetite for opportunities to participate in solar and other renewable energy projects may be significant enough that more bond offerings will follow on the heels of this one. As the Brookings-Rockefeller Project on State and Metropolitan Innovation found in an April 2014 report, Clean Energy FinanceThrough the Bond Market:A New Option for Progress, "Bond finance holds tremendous potential for clean energy investment, at levels in the tens of billions of dollars in the next several years." If SolarCity is indeed successful in attractive individual bond investors, other solar developers like First Solar, Inc. and Sunrun may soon follow suit with solar bond offerings of their own.
Solar energy company SolarCity Corporation appears to think so, as this morning it filed a registration statement with the U.S. Securities and Exchange Commission to issue up to $200 million in solar bonds. SolarCity describes the move as "the nation’s first registered public offering of solar bonds." What does SolarCity's solar bond offering mean for solar energy?
 |
| Solar panels on a residential rooftop in Massachusetts. |
By some metrics, SolarCity is the largest developer of residential solar photovoltaic projects in the U.S. The company says it is currently providing more than one out of every three new solar power systems in the U.S., and notes that it "installed more residential solar in the second quarter of 2014 than its next 50 competitors combined." While SolarCity develops projects under several financial models, its typically installs rooftop solar panels at its customers' sites with no upfront costs to the customer, who then pays the company every month for leasing the facilities or for the electricity it uses. These long-term contracts create more stable ongoing revenues for SolarCity compared to those experienced by developers of turnkey projects who may end their relationship after the project is commissioned.
SolarCity's model has proved attractive to capital, as it has been involved with financing the installation of approximately $5 billion in renewable energy assets. Much of the capital SolarCity needs to develop these projects has come from investments from major banks and corporations including US Bancorp and Google Inc., as well as individuals owning shares of the company's stock (traded as SCTY).
SolarCity has also turned to debt offerings, making three private placements of solar bonds in the last year. Generally speaking, SolarCity will pay returns on the bonds using income generated from customers' monthly payments. Because this income stream is both relatively stable and predictable, it should enable repayment of the bonds plus a steady yield.
But no company has previously publicly offered solar bonds of this type in the U.S. SolarCity thus views its publicly offered solar bonding model as unique, in that it gives individual investors access to new investment opportunities -- and in turn, it may give SolarCity access to a whole lot more money -- up to $200 million in this round, with the prospect of more to come.
Under SolarCity's new offering, investors will be able to purchase solar bonds for as little as $1,000, with maturities ranging from one year to seven years and interest rates of up to 4 percent. The relatively short maturity of these bonds, compared to those previously offered to institutional investors, helps reduce the risk that during the bonds' lives utility rates will change in a way that hurts their economics.
The company notes that solar bonds will be available to all U.S. investors who are at least 18 years old and meet SolarCity’s eligibility requirements, with no fees for purchase. Indeed, the relatively low $1,000 minimum investment for this solar bond offering highlights SolarCity's strategy of targeting the millions of small or "retail" investors. To facilitate these individual investors' access to the bonds, the company launched a new online investment site (solarbonds.solarcity.com).
How will the new solar bond offering affect SolarCity and the pace of solar development in the US? With a market capitalization of $4.2 billion, SolarCity is relatively large compared to the $200 million that it may raise pursuant to the current public bond offering. Nevertheless, individual investors' appetite for opportunities to participate in solar and other renewable energy projects may be significant enough that more bond offerings will follow on the heels of this one. As the Brookings-Rockefeller Project on State and Metropolitan Innovation found in an April 2014 report, Clean Energy FinanceThrough the Bond Market:A New Option for Progress, "Bond finance holds tremendous potential for clean energy investment, at levels in the tens of billions of dollars in the next several years." If SolarCity is indeed successful in attractive individual bond investors, other solar developers like First Solar, Inc. and Sunrun may soon follow suit with solar bond offerings of their own.
NJ regulators reject offshore wind project
Thursday, March 20, 2014
The New Jersey Board of Public Utilities has voted against extending ratepayer subsidies to an offshore wind project proposed by developer Fishermen's Energy, challenging the project's financial viability.
Back in 2011, Fishermen's Energy proposed a 25-megawatt offshore wind pilot project to be located off Atlantic City. The developer applied to the Board of Public Utilities for ratepayer support under New Jersey's Offshore Wind Economic Development Act of 2010. That law directed the Board of Public Utilities to develop a program to require utilities to source a percentage of the electricity they sell in New Jersey from one or more qualified offshore wind projects. To track energy from offshore wind, the law envisioned the creation of offshore renewable energy certificates, or ORECs, that could be sold by qualified offshore wind projects to the load-serving utilities. The concept was that given the relatively high costs and uncertainty of offshore wind, no project could be financed or built without a steady revenue stream from OREC sales.
But the New Jersey project appeared to stall before the Board. Charged with creating the OREC program and evaluating whether the Fishermen's Energy project could qualify to produce ORECs, the Board was faced with serious technical tasks. As the regulatory process for the Fishermen's Energy project lengthened -- ultimately stretching to over 1,000 days -- Board staff raised concerns over the financial viability of the project, as well as over the impact of the requested subsidy to ratepayer costs. Despite trimming the project's estimated costs to $188 million, these concerns remained, leading Board staff to recommend denial of Fishermen's Energy's request for OREC certification.
Yesterday, the Board of Public Utilities rejected Fishermen’s Energy’s proposal by a unanimous 4-0 decision. While the Board's formal written order has not yet been released, expect it to explain the Board's reasoning in more detail when it surfaces next week. In the meantime, Fishermen’s Energy is undoubtedly considering its options, which may include dropping the project, appealing the Board's rejection, or finding alternative ways to de-risk and finance the project.
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| The New Jersey coast near Atlantic City, seen from above. |
Back in 2011, Fishermen's Energy proposed a 25-megawatt offshore wind pilot project to be located off Atlantic City. The developer applied to the Board of Public Utilities for ratepayer support under New Jersey's Offshore Wind Economic Development Act of 2010. That law directed the Board of Public Utilities to develop a program to require utilities to source a percentage of the electricity they sell in New Jersey from one or more qualified offshore wind projects. To track energy from offshore wind, the law envisioned the creation of offshore renewable energy certificates, or ORECs, that could be sold by qualified offshore wind projects to the load-serving utilities. The concept was that given the relatively high costs and uncertainty of offshore wind, no project could be financed or built without a steady revenue stream from OREC sales.
But the New Jersey project appeared to stall before the Board. Charged with creating the OREC program and evaluating whether the Fishermen's Energy project could qualify to produce ORECs, the Board was faced with serious technical tasks. As the regulatory process for the Fishermen's Energy project lengthened -- ultimately stretching to over 1,000 days -- Board staff raised concerns over the financial viability of the project, as well as over the impact of the requested subsidy to ratepayer costs. Despite trimming the project's estimated costs to $188 million, these concerns remained, leading Board staff to recommend denial of Fishermen's Energy's request for OREC certification.
Yesterday, the Board of Public Utilities rejected Fishermen’s Energy’s proposal by a unanimous 4-0 decision. While the Board's formal written order has not yet been released, expect it to explain the Board's reasoning in more detail when it surfaces next week. In the meantime, Fishermen’s Energy is undoubtedly considering its options, which may include dropping the project, appealing the Board's rejection, or finding alternative ways to de-risk and finance the project.
Maine PUC declines to OK Statoil offshore wind term sheet
Thursday, October 4, 2012
Today the Maine Public Utilities Commission declined to approve a term sheet offered by Statoil North America, Inc. for a long-term power purchase agreement from its proposed Hywind Maine floating offshore wind project.
In 2010, Maine enacted a law designed to support the development of offshore wind and other marine renewable energy projects. Among other features, that law required the state Public Utilities Commission to conduct a competitive solicitation for proposals for deep-water offshore wind energy pilot projects, meaning grid-tied floating wind projects at least 10 nautical miles offshore. The statute gave the commission authority to direct mainland utilities to enter into power purchase agreements with one or more responding developers if certain minimum criteria were met. This authority was discretionary, meaning the commission could choose not to order the utilities to sign a deal even if it met those criteria.
In September 2010, the commission issued its request for proposals under the program. Over the ensuing years, Statoil emerged as the apparent leading respondent, proposing the "Hywind Maine" project, a four-turbine, twelve megawatt project south of Boothbay Harbor. Commission staff and Statoil negotiated the terms of a proposed power purchase agreement, which became public this summer. Among those terms was a proposed energy price of between $290 and $320 per megawatt-hour, escalating annually, for the first 41 gigawatt-hours of energy produced each year.
That term sheet was the subject of deliberations by the Maine commission this morning. After two hours of discussion, two of the three commissioners had stated that they would vote against approving the term sheet. They expressed concerns about the cost of the contract, as well as uncertainty over the deal's benefit to Maine and Maine ratepayers.
The Maine commission's action bears some resemblance to that of the Rhode Island Public Utilities Commission in 2010 when it rejected a proposed contract between utility National Grid and offshore wind developer Deepwater Wind on the grounds that $244 per megawatt-hour was not a "commercially reasonable" price. The Rhode Island commission ultimately approved a renegotiated deal with Deepwater Wind at a comparable price. Similarly, the Maine commission invited Statoil to revise its proposal to offer more benefits to Maine, and to present a renegotiated deal for further deliberation. Will Statoil be able to sweeten its offer and convince the commission that its contract is a good deal for Maine?
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| Sutton Island, Maine, about 80 miles downeast of the proposed Hywind Maine project. |
In September 2010, the commission issued its request for proposals under the program. Over the ensuing years, Statoil emerged as the apparent leading respondent, proposing the "Hywind Maine" project, a four-turbine, twelve megawatt project south of Boothbay Harbor. Commission staff and Statoil negotiated the terms of a proposed power purchase agreement, which became public this summer. Among those terms was a proposed energy price of between $290 and $320 per megawatt-hour, escalating annually, for the first 41 gigawatt-hours of energy produced each year.
That term sheet was the subject of deliberations by the Maine commission this morning. After two hours of discussion, two of the three commissioners had stated that they would vote against approving the term sheet. They expressed concerns about the cost of the contract, as well as uncertainty over the deal's benefit to Maine and Maine ratepayers.
The Maine commission's action bears some resemblance to that of the Rhode Island Public Utilities Commission in 2010 when it rejected a proposed contract between utility National Grid and offshore wind developer Deepwater Wind on the grounds that $244 per megawatt-hour was not a "commercially reasonable" price. The Rhode Island commission ultimately approved a renegotiated deal with Deepwater Wind at a comparable price. Similarly, the Maine commission invited Statoil to revise its proposal to offer more benefits to Maine, and to present a renegotiated deal for further deliberation. Will Statoil be able to sweeten its offer and convince the commission that its contract is a good deal for Maine?
Massachusetts increases renewable energy incentives
Monday, August 13, 2012
Energy legislation signed by Massachusetts Governor Deval Patrick earlier this month creates new opportunities for renewable energy projects in New England.
Finally enacted as Senate Bill 2395, the bill titled "An Act relative to competitively priced electricity in the Commonwealth" (37-page PDF) represents a combination of legislative proposals offered during the 2012 session. The Act expands opportunities for renewable energy and energy efficiency, while seeking to manage increases in the cost of energy to consumers.
A number of the Act's provisions improve opportunities for renewable electricity production in Massachusetts and other New England states. Building on the Green Communities Act of 2008, the new law increases the amount of electricity that electric distribution companies may purchase from renewable generating facilities under long-term contracts. Previous law had required utilities to procure up to 3% of their electricity through long-term power purchase agreements with independent renewable energy developers.
The 2012 act amends the Green Communities Act by requiring distribution companies to solicit 10 to 20-year power purchase agreements from renewable developers for up to an additional 4% of the utilities' annual load. By the end of 2016, the Commonwealth's distribution companies will conduct two rounds of joint solicitations for the new contracts. Unlike previous renewable PPA negotiations such as led utility National Grid to select offshore wind developer Cape Wind as a renewable energy supplier, the new contracts must be negotiated through a competitive bid process.
The new law also provides a boon for distributed generation, requiring 10% of the newly-mandated supply to come from newly developed, small, emerging or diverse renewable energy distributed generation facilities located in its service territory. Standards for these distributed generation projects require a maximum project capacity no greater than 6 megawatts. Eligible distributed generation projcts cannot be net metering facilities, and must rely on a technology with no more than 30 megawatts of installed capacity in Massachusetts as of April 2012.
Under the Massachusetts renewable portfolio standard, projects eligible for this incentive may be built in any New England state, New York, or eastern Canada.
Finally enacted as Senate Bill 2395, the bill titled "An Act relative to competitively priced electricity in the Commonwealth" (37-page PDF) represents a combination of legislative proposals offered during the 2012 session. The Act expands opportunities for renewable energy and energy efficiency, while seeking to manage increases in the cost of energy to consumers.
A number of the Act's provisions improve opportunities for renewable electricity production in Massachusetts and other New England states. Building on the Green Communities Act of 2008, the new law increases the amount of electricity that electric distribution companies may purchase from renewable generating facilities under long-term contracts. Previous law had required utilities to procure up to 3% of their electricity through long-term power purchase agreements with independent renewable energy developers.
The 2012 act amends the Green Communities Act by requiring distribution companies to solicit 10 to 20-year power purchase agreements from renewable developers for up to an additional 4% of the utilities' annual load. By the end of 2016, the Commonwealth's distribution companies will conduct two rounds of joint solicitations for the new contracts. Unlike previous renewable PPA negotiations such as led utility National Grid to select offshore wind developer Cape Wind as a renewable energy supplier, the new contracts must be negotiated through a competitive bid process.
The new law also provides a boon for distributed generation, requiring 10% of the newly-mandated supply to come from newly developed, small, emerging or diverse renewable energy distributed generation facilities located in its service territory. Standards for these distributed generation projects require a maximum project capacity no greater than 6 megawatts. Eligible distributed generation projcts cannot be net metering facilities, and must rely on a technology with no more than 30 megawatts of installed capacity in Massachusetts as of April 2012.
Under the Massachusetts renewable portfolio standard, projects eligible for this incentive may be built in any New England state, New York, or eastern Canada.
Energy projects installed in May 2012
Tuesday, July 3, 2012
A report released this week by federal energy regulators documents the composition of additions to the U.S.'s portfolio of electricity resources. The May 2012 Energy Infrastructure Update released by the Federal Energy Regulatory Commission's Office of Energy Projects provides a summary of newly-built and expanded electric generation facilities. This snapshot of what happened in May 2012 illustrates trends in the electric industry, including a focus on renewable energy and natural gas in project development.
According to the report, 561 megawatts of new or expanded electric generation capacity came online in May 2012. Of this new installed capacity, the largest share -- 228 MW -- came from wind. Most of this new capacity comes from a single project, E.ON Climate & Renewables North America, LLC’s Magic Valley Wind Farm I in Texas. The Magic Valley I project is comprised of 112 Vestas V100 1.8-MW turbines, for a total nameplate capacity of 202 MW.
The second-largest resource class of new generation capacity in May 2012 comes from biomass, with 166 MW of new biomass capacity installed in May. As with wind, Texas hosts the bulk of this new capacity. The largest new biomass project is a 100 MW wood-fired plant built in Nacogdoches County, Texas, by Southern Company, financed in part through a long-term power purchase agreement with Austin Energy to buy the power.
Solar-powered generation provides the third-largest class of capacity newly installed in May 2012. Eleven new projects came online in May, totaling 149 MW of new capacity. The largest of these is Enbridge Inc.’s 50 MW Silver State North Solar Project. This project, located in Clark County, Nevada, is the first utility-scale solar facility built on federal land managed by the Bureau of Land Management. Its output will be sold to NV Energy under a long-term PPA.
Together, these three renewable resources -- wind, biomass, and solar -- represent 543 out of the 561 MW installed in May 2012. Other fuels like coal and natural gas played a relatively minor role in terms of new capacity installed in May. Nevertheless, the year-to-date cumulative data shows that natural gas powers the largest share of projects installed in 2012 -- 2,811 MW out of the 6,225 MW installed so far in 2012.
According to the report, 561 megawatts of new or expanded electric generation capacity came online in May 2012. Of this new installed capacity, the largest share -- 228 MW -- came from wind. Most of this new capacity comes from a single project, E.ON Climate & Renewables North America, LLC’s Magic Valley Wind Farm I in Texas. The Magic Valley I project is comprised of 112 Vestas V100 1.8-MW turbines, for a total nameplate capacity of 202 MW.
The second-largest resource class of new generation capacity in May 2012 comes from biomass, with 166 MW of new biomass capacity installed in May. As with wind, Texas hosts the bulk of this new capacity. The largest new biomass project is a 100 MW wood-fired plant built in Nacogdoches County, Texas, by Southern Company, financed in part through a long-term power purchase agreement with Austin Energy to buy the power.
Solar-powered generation provides the third-largest class of capacity newly installed in May 2012. Eleven new projects came online in May, totaling 149 MW of new capacity. The largest of these is Enbridge Inc.’s 50 MW Silver State North Solar Project. This project, located in Clark County, Nevada, is the first utility-scale solar facility built on federal land managed by the Bureau of Land Management. Its output will be sold to NV Energy under a long-term PPA.
Together, these three renewable resources -- wind, biomass, and solar -- represent 543 out of the 561 MW installed in May 2012. Other fuels like coal and natural gas played a relatively minor role in terms of new capacity installed in May. Nevertheless, the year-to-date cumulative data shows that natural gas powers the largest share of projects installed in 2012 -- 2,811 MW out of the 6,225 MW installed so far in 2012.
Solar-powered highway in Colorado
Thursday, June 28, 2012
Facilities along a 17-mile segment of a Colorado toll highway are now powered by solar-generated electricity. The project, which involved the construction of 22 solar installation sites along the route, was financed through a long-term power purchase agreement that allows the highway authority to avoid direct exposure to the capital costs of construction.
Colorado E-470 is a beltway that loops around the east side of the Denver metropolitan area. The road is administered by the E-470 Public Highway Authority, a political subdivision of the State of Colorado. Much of the authority's expenses center on road maintenance, but electricity costs are one component of its operational budget. For example, electricity is used to power streetlights, signs, toll collection equipment, toll plazas, maintenance facilities and the authority's administrative headquarters.
Looking to reduce its operational costs, the highway authority focused on the development of solar photovoltaic facilities. Rather than developing the project itself, or purchasing a turnkey project, the authority entered into a deal with Adamas Energy Investments to develop the project. Under that deal, Adamas and solar developer Martifer Solar USA constructed solar PV electric generation facilities along part of E-470 at no direct cost to the authority. Instead, the authority entered into a 20-year solar power purchase agreement with Adamas to purchase the project's output.
According to EVStudio, the designer of the piers for the installations, the project is anticipated to produce 975,436 kWh in its first year of operation. The exact pricing terms of the deal are not readily available to the public, but the authority has stated that it anticipates paying Adamas less per kilowatt-hour than it would to incumbent utility Xcel Energy. According to the authority, the first six years' pricing is fixed, followed by a fixed annual increase for the 14 remaining years of the PPA.
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| Solar photovoltaic panels at Goblin Valley State Park, Utah. |
Colorado E-470 is a beltway that loops around the east side of the Denver metropolitan area. The road is administered by the E-470 Public Highway Authority, a political subdivision of the State of Colorado. Much of the authority's expenses center on road maintenance, but electricity costs are one component of its operational budget. For example, electricity is used to power streetlights, signs, toll collection equipment, toll plazas, maintenance facilities and the authority's administrative headquarters.
Looking to reduce its operational costs, the highway authority focused on the development of solar photovoltaic facilities. Rather than developing the project itself, or purchasing a turnkey project, the authority entered into a deal with Adamas Energy Investments to develop the project. Under that deal, Adamas and solar developer Martifer Solar USA constructed solar PV electric generation facilities along part of E-470 at no direct cost to the authority. Instead, the authority entered into a 20-year solar power purchase agreement with Adamas to purchase the project's output.
According to EVStudio, the designer of the piers for the installations, the project is anticipated to produce 975,436 kWh in its first year of operation. The exact pricing terms of the deal are not readily available to the public, but the authority has stated that it anticipates paying Adamas less per kilowatt-hour than it would to incumbent utility Xcel Energy. According to the authority, the first six years' pricing is fixed, followed by a fixed annual increase for the 14 remaining years of the PPA.
Maine tidal PPA terms for ORPC
Thursday, May 3, 2012
Last month, the Maine Public Utilities Commission approved the terms of a 20-year power purchase agreement between three utilities and Ocean Renewable Power Company. Projected for initial development later this year, ORPC's Maine Tidal Energy Project would ultimately include a series of hydrokinetic turbine generator units spread across three project sites and phases.
Acting under a 2010 state law, the Maine PUC held a request for proposals for long-term contracts for deep-water offshore wind pilot projects and tidal energy demonstration projects. The law required applicants to demonstrate that their project will provide tangible economic benefits to the state, as well as a commitment to invest in related manufacturing facilities in Maine.
ORPC responded to the RFP, and was ultimately selected by the PUC for a contract. While some details of the final power purchase agreement remain to be negotiated, last month PUC approved a term sheet specifying pricing terms and a variety of non-pricing terms.
Under the term sheet, ORPC will sell the utilities energy and capacity from the Maine project. The price of energy will start at 21.5 cents per kilowatt-hour in the first year, escalating at 2% per year over the 20-year contract term. If ORPC can qualify the project for capacity payments in the New England market - another energy-related product - it will receive the prevailing market price, although the grid operator has recently denied capacity payments to other renewable resources in eastern and northern Maine. The deal does not include any renewable energy credits the project earns, which ORPC could retain or sell separately.
The term sheet approved by the Commission also include a series non-pricing terms intended to ensure that the state realizes the economic development benefits required by statute. These terms include a variety of commitments by ORPC, including:
The parties are now negotiating the final details of the contract. Expect the PUC to deliberate on a final contract later this year.
Acting under a 2010 state law, the Maine PUC held a request for proposals for long-term contracts for deep-water offshore wind pilot projects and tidal energy demonstration projects. The law required applicants to demonstrate that their project will provide tangible economic benefits to the state, as well as a commitment to invest in related manufacturing facilities in Maine.
ORPC responded to the RFP, and was ultimately selected by the PUC for a contract. While some details of the final power purchase agreement remain to be negotiated, last month PUC approved a term sheet specifying pricing terms and a variety of non-pricing terms.
Under the term sheet, ORPC will sell the utilities energy and capacity from the Maine project. The price of energy will start at 21.5 cents per kilowatt-hour in the first year, escalating at 2% per year over the 20-year contract term. If ORPC can qualify the project for capacity payments in the New England market - another energy-related product - it will receive the prevailing market price, although the grid operator has recently denied capacity payments to other renewable resources in eastern and northern Maine. The deal does not include any renewable energy credits the project earns, which ORPC could retain or sell separately.
The term sheet approved by the Commission also include a series non-pricing terms intended to ensure that the state realizes the economic development benefits required by statute. These terms include a variety of commitments by ORPC, including:
- to maintain or establish manufacturing, assembly, and testing operations in Maine
- to continue partnerships with entities in the downeast Washington County region
- to upgrade local distribution lines in Lubec, as needed to connect the project's power to the mainland grid
- to create and/or retain at least 80 direct full-time equivalent jobs in Maine during the development, construction and installation of the project
- to create and/or retain at least 12 direct full-time equivalent jobs in Maine during the operation and maintenance phase of the project
- to use commercially reasonable efforts to expend at least 50% of the project's capital investments and 50% of the operating expenditures in Maine
The parties are now negotiating the final details of the contract. Expect the PUC to deliberate on a final contract later this year.
Maine regulators approve tidal energy PPA concept
Wednesday, April 25, 2012
Yesterday, the Maine Public Utilities Commission approved the terms of a power purchase agreement between three large utilities and a hydrokinetic tidal power project in Maine waters.
Hydrokinetic energy projects produce electricity from moving water like tides, waves, ocean currents, or rivers, typically without dams. As I noted yesterday, a 2010 Maine law required the PUC to conduct a competitive process to solicit proposals for long-term contracts for offshore wind and tidal projects. The PUC received multiple submissions in response. Commission staff have been negotiating with some of the bidders, and yesterday approved a proposal by Ocean Renewable Power Co. to sell the output of a small tidal project in Cobscook Bay to Maine's three largest utilities.
Under the terms approved the Commission, ORPC will receive a 20-year contract with utilities Central Maine Power Co., Bangor Hydro-Electric Co., and Maine Public Service Co. to sell the output of its underwater tidal power generation units. ORPC plans to install the first of these units in Cobscook Bay this summer, and plans to expand its pilot project to include sites off Lubec and Eastport in the next 4 years.
While many of the terms of the resulting contract remain to be worked out, one piece appears firm: the price. Utilities will pay 21.5 cents per kilowatt-hour for the tide-generated electricity in the first year; this base price of 21.5 cents will escalate at 2% per year, reaching a price of about 39 cents per kWh in the final contract year. (By way of comparison, the Cape Wind offshore wind PPA approved in Massachusetts starts at 18.7 cents per kWh, with a 3.5% annual escalator over its 15 year term. The ORPC initial rate is over twice the average rate currently paid by Maine utility customers on "standard offer" default service, or about 5 times higher than the current wholesale price in the New England market.)
For ORPC, the contract is a significant boon. Securing a 20-year power purchase agreement should greatly assist the developer in securing financing for the project. This project is designed as a demonstration or pilot project, but may be able to serve as a proof that ORPC's technology and installation systems will work on a larger scale.
For ratepayers, the volume of the contract is relatively low - as licensed by FERC, the Cobscook Project has a maximum capacity of 300 kW - meaning that its above-market costs will be diluted in the much larger pool of power consumed in Maine. Nevertheless, if the contract volume grows as ORPC builds more of its scalable tidal generation units, those costs will become less and less dilute. On the other hand, the contract itself - which still needs approval by the PUC once it is finally negotiated - may include other products or commodities such as capacity or renewable energy credits (RECs). Developers typically prefer securing long-term contracts for as many commodities as possible, which helps solidify their future revenues, but it can make it harder to compare two contracts.
Many tidal projects today face high capital costs, let alone research and development expenses, but many believe that their fuel-free nature will ultimately enable tidal power to have a low fundamental cost of production of electricity in the future. ORPC's project may shed some light on how that belief fares in the Gulf of Maine.
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| Low tide at Preble Cove, Great Cranberry Island, Maine. |
Under the terms approved the Commission, ORPC will receive a 20-year contract with utilities Central Maine Power Co., Bangor Hydro-Electric Co., and Maine Public Service Co. to sell the output of its underwater tidal power generation units. ORPC plans to install the first of these units in Cobscook Bay this summer, and plans to expand its pilot project to include sites off Lubec and Eastport in the next 4 years.
While many of the terms of the resulting contract remain to be worked out, one piece appears firm: the price. Utilities will pay 21.5 cents per kilowatt-hour for the tide-generated electricity in the first year; this base price of 21.5 cents will escalate at 2% per year, reaching a price of about 39 cents per kWh in the final contract year. (By way of comparison, the Cape Wind offshore wind PPA approved in Massachusetts starts at 18.7 cents per kWh, with a 3.5% annual escalator over its 15 year term. The ORPC initial rate is over twice the average rate currently paid by Maine utility customers on "standard offer" default service, or about 5 times higher than the current wholesale price in the New England market.)
For ORPC, the contract is a significant boon. Securing a 20-year power purchase agreement should greatly assist the developer in securing financing for the project. This project is designed as a demonstration or pilot project, but may be able to serve as a proof that ORPC's technology and installation systems will work on a larger scale.
For ratepayers, the volume of the contract is relatively low - as licensed by FERC, the Cobscook Project has a maximum capacity of 300 kW - meaning that its above-market costs will be diluted in the much larger pool of power consumed in Maine. Nevertheless, if the contract volume grows as ORPC builds more of its scalable tidal generation units, those costs will become less and less dilute. On the other hand, the contract itself - which still needs approval by the PUC once it is finally negotiated - may include other products or commodities such as capacity or renewable energy credits (RECs). Developers typically prefer securing long-term contracts for as many commodities as possible, which helps solidify their future revenues, but it can make it harder to compare two contracts.
Many tidal projects today face high capital costs, let alone research and development expenses, but many believe that their fuel-free nature will ultimately enable tidal power to have a low fundamental cost of production of electricity in the future. ORPC's project may shed some light on how that belief fares in the Gulf of Maine.
Maine PUC considers offshore wind, tidal
Tuesday, April 24, 2012
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| Petit Manan Light, several miles off the Maine coast. |
In recent years, coastal states have become excited by the possibility of developing offshore wind and tidal energy resources. Proponents hope that technological advances will enable both cost-effective energy production and economic development as the offshore wind sector gains a foothold. In 2010, following record oil prices, the Maine Legislature enacted a law directing the Public Utilities Commission to hold a competitive solicitation for offshore wind proposals. The law, P.L. 2009, ch. 615, requires the PUC to solicit proposals for long-term contracts to supply installed capacity and associated renewable energy and renewable energy credits from one or more deep-water offshore wind energy pilot projects or tidal energy demonstration projects. Projects must employ one or more floating wind energy turbines in the Gulf of Maine, in water at least 300 feet deep and no less than 10 nautical miles offshore, and must be connected to the mainland grid. The program may also include proposals by small-scale tidal power projects for similar long-term power purchase agreements.
In September 2010, the Maine PUC issued a request for proposals under the program. Multiple bidders may have responded, although a subsidiary of Norwegian energy company Statoil may be the only entity to publicly announce its interest in developing a floating offshore wind project off Maine.
The Public Utilities Commission has placed the offshore wind contract docket on its agenda for today's deliberations as "Consideration of Long Term Contract Term Sheet". The Maine PUC has not previously deliberated any long-term power purchase agreements for offshore wind or tidal power, but its past practice for land-based renewable projects suggests a possible procedural path. If the Commission finds the terms of the proposal to be satisfactory and compliant with law, it may approve the term sheet and direct the bidder to negotiate a final contract with one or more Maine utilities. Alternatively, the Commission could reject the term sheet and invite the bidder to negotiate more favorable terms.
Deliberations start at 10:00 a.m. Will the Maine PUC show interest in the deepwater offshore wind or tidal power proposal before it today?
Google grows wind power supply
Monday, January 16, 2012
Google Energy LLC, a subsidiary of internet search company Google Inc., recently informed federal regulators of a long-term power purchase agreement with a 100.8-megawatt wind-powered electric generation project in Oklahoma.
Under the deal, Google agreed to buy all of the energy output from Minco Wind II, LLC's wind project for a term of 20 years. Minco Wind II is operated by a subsidiary of NextEra Energy Resources. As part of the deal, Google can claim that it is powering a data center in Pryor, OK, with power from the wind project.
The Oklahoma PPA nearly doubles the amount of wind capacity under contract by Google. In 2010, Google Energy entered into a power purchase agreement to buy 114 MW of wind from Garden Wind, LLC. Garden Wind, also a NextEra subsidiary, owns and operates a 150 MW wind project in Iowa. Garden Wind sold Google Energy a 76% share of the project's output for a term of 20 years. In addition, Google indirectly owns a 20.5% interest in Peace Garden Wind, LLC, which owns and operates about 169 MW of wind generation in the central region.
This comes two months after Google announced it was scaling back its program aimed at making renewable energy cost less than coal. Google's RE
Under the deal, Google agreed to buy all of the energy output from Minco Wind II, LLC's wind project for a term of 20 years. Minco Wind II is operated by a subsidiary of NextEra Energy Resources. As part of the deal, Google can claim that it is powering a data center in Pryor, OK, with power from the wind project.
The Oklahoma PPA nearly doubles the amount of wind capacity under contract by Google. In 2010, Google Energy entered into a power purchase agreement to buy 114 MW of wind from Garden Wind, LLC. Garden Wind, also a NextEra subsidiary, owns and operates a 150 MW wind project in Iowa. Garden Wind sold Google Energy a 76% share of the project's output for a term of 20 years. In addition, Google indirectly owns a 20.5% interest in Peace Garden Wind, LLC, which owns and operates about 169 MW of wind generation in the central region.
This comes two months after Google announced it was scaling back its program aimed at making renewable energy cost less than coal. Google's RE
Community-based renewable energy in Maine
Friday, December 30, 2011
An innovative program in Maine seeks to facilitate the development of community-based renewable energy projects. The program offers significant incentives for the development of qualified electric generation projects of up to 10 MW in size.
In 2009, the Maine legislature enacted a law establishing the Community-Based Renewable Energy Pilot Program to encourage the sustainable development of community-based renewable energy. By community-based, Maine's program targets locally-owned community-scale projects (as opposed to large-scale renewable projects owned primarily by out-of-state entities).
Under the program, qualified renewable energy projects can receive significant incentives including a long-term contract to sell the facility’s output to a Maine transmission and distribution utility for up to 20 years at average prices up to $100 per MWh (equivalent to 10¢ per kWh). This incentive is attractive because not only can the contract prices be above average market prices, but also the long-term power purchase agreement makes projects easier to finance by enhancing revenue certainty.
Eligible projects can apply to the Maine Public Utilities Commission for certification as community-based renewable energy projects. This process involves making public filings, negotiating with Commission staff, and demonstrating that the project meets the program’s qualification requirements. These include restrictions on resource type, nameplate capacity, and ownership.
Under the pilot program, eligible resources include:
Once certified, a qualified project can choose either of two incentives: a long-term contract for the output of the facility with a transmission and distribution utility, or a renewable energy credit (REC) multiplier giving a 50% bonus in the amount of RECs produced.
To date, most have viewed the long-term contract as the more attractive option. Under this incentive, projects meeting the program’s requirements can obtain a contract at a fixed or variable price, provided that two criteria are met. First, the average price per kilowatt-hour must not exceed 10 cents. Second, the cost of the contract must not exceed the cost of the project plus a reasonable rate of return on investment as determined by the Commission. These contracts may be approved for up to 20 year terms. Projects smaller than 1 MW can contract directly with the utility, while larger projects go through a competitive process held periodically by the Commission.
What will 2012 bring for Maine's community-based renewable energy pilot program?
In 2009, the Maine legislature enacted a law establishing the Community-Based Renewable Energy Pilot Program to encourage the sustainable development of community-based renewable energy. By community-based, Maine's program targets locally-owned community-scale projects (as opposed to large-scale renewable projects owned primarily by out-of-state entities).
Under the program, qualified renewable energy projects can receive significant incentives including a long-term contract to sell the facility’s output to a Maine transmission and distribution utility for up to 20 years at average prices up to $100 per MWh (equivalent to 10¢ per kWh). This incentive is attractive because not only can the contract prices be above average market prices, but also the long-term power purchase agreement makes projects easier to finance by enhancing revenue certainty.
Eligible projects can apply to the Maine Public Utilities Commission for certification as community-based renewable energy projects. This process involves making public filings, negotiating with Commission staff, and demonstrating that the project meets the program’s qualification requirements. These include restrictions on resource type, nameplate capacity, and ownership.
Under the pilot program, eligible resources include:
- fuel cells
- tidal power
- solar energy
- wind systems
- geothermal systems
- hydroelectric generators
- generators fueled by landfill gas
- biomass generators whose fuel includes anaerobic digestion of agricultural products, byproducts or wastes.
Once certified, a qualified project can choose either of two incentives: a long-term contract for the output of the facility with a transmission and distribution utility, or a renewable energy credit (REC) multiplier giving a 50% bonus in the amount of RECs produced.
To date, most have viewed the long-term contract as the more attractive option. Under this incentive, projects meeting the program’s requirements can obtain a contract at a fixed or variable price, provided that two criteria are met. First, the average price per kilowatt-hour must not exceed 10 cents. Second, the cost of the contract must not exceed the cost of the project plus a reasonable rate of return on investment as determined by the Commission. These contracts may be approved for up to 20 year terms. Projects smaller than 1 MW can contract directly with the utility, while larger projects go through a competitive process held periodically by the Commission.
What will 2012 bring for Maine's community-based renewable energy pilot program?
March 8, 2011 - Maryland's long-term contracting for offshore wind
Tuesday, March 8, 2011
Offshore wind development in the mid-Atlantic states is moving forward - what will it cost? The Maryland legislature is considering a plan by Governor Martin O'Malley to kickstart offshore wind development. The Governor has said that offshore wind projects are a critical part of how Maryland can meet the state's renewable energy goal of sourcing 20 percent of its electricity from renewable sources by 2022, but without long-term contracts, it is unclear whether enough (or any) projects would be built. To get over this hurdle, Governor O'Malley's plan would require Maryland utilities to sign long-term contracts to buy offshore wind power at prices above the current market rate. Project developers view the contracts, lasting up to 25 years, as essential to getting the projects financed and built.
So how much will this cost? Figures diverge by a factor of more than sixfold. Governor O'Malley's estimates are that the plan will cost the average ratepayer $1.44 per month, but that figure has been called into question by other more recent analyses. The Maryland legislature's budget analyst's has concluded that the monthly cost to average ratepayers will be $3.61, while Maryland's Public Service Commission has predicted a range of monthly costs between $2.16 and $8.70.
December 8, 2010 - Deepwater Wind proposes expansion of Rhode Island Sound project
Wednesday, December 8, 2010
Renewable developer Deepwater Wind has announced today its plans to double the size of its proposed Rhode Island Sound offshore wind project. Under the current proposal, Deepwater's second-generation development will now consist of 200 turbines to be installed in federal waters off Rhode Island and Massachusetts. Deepwater hopes to commence construction of the project in 2014, bringing the first turbines into operation in 2015.
What price will Deepwater get for its power? Looking at other offshore wind projects is illustrative of the kinds of pricing we might expect. For example, Deepwater Wind is also developing a smaller 8-turbine demonstration project in Rhode Island state waters, the Block Island Wind Farm. The developer has already secured one major state approval to construct the project, although this approval is currently being challenged in state Supreme Court. The Rhode Island PUC has approved a contract with utility National Grid establishing a maximum starting price of 24.4 cents per kWh, with 3.5 percent increases over the the 20-year life of the deal.
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| A recent sunset over Maine's Merrymeeting Bay. |
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