U.S. energy regulators have revised their policies, and will no longer allow master limited partnership (MLP) interstate natural gas and oil pipelines to recover an income tax allowance in their cost-of-service rates. The Federal Energy Regulatory Commission issued its Revised Policy Statement on Treatment of Income Taxes following a 2016 federal court order addressing the topic.
At issue is the Commission's policy on how MLP pipelines may set their cost-based rates. As described by the Commission, an MLP is a partnership form in which units are traded on exchanges much like corporate stock. To be treated as an
MLP for Federal income tax purposes, an
MLP must
receive at least 90 percent of its income from certain qualifying sources, including natural
gas and oil
transportation.
MLP pipelines
are not corporations, but are pass-through
entities. This means that MLPs are not taxed at the pipeline level; instead, for tax
purposes, the partnership agreement allocates to each partner a share of the partnership’s
taxable income, and
each partner is personally responsible for paying income taxes on the
partnership’s net taxable income.
From 2005 until a 2016 court ruling, the Commission's 2005 Income Tax Policy Statement allowed all partnership entities (including MLPs) to recover an income tax allowance for the partners' tax costs, much like a corporation receives an income tax allowance for its corporate income tax costs. Alongside this income tax policy, the Commission has used a discounted cash flow (DCF) methodology to determine the rate of return regulated entities need to attract capital.
In 2008, a pipeline MLP named SFPP, L.P. filed a cost-of-service rate increase to increase the rates for a line running between California and Arizona. Shippers protested the filed rates, including the interaction between (a) the
Commission’s policy permitting an income tax allowance policy for partnership business
forms (such as SFPP) and (b) the Commission’s DCF methodology used to determine a
cost-of-service rate of return. The Commission eventually issued orders addressing issues in the case including the income tax allowance issue, which were challenged in court.
On appeal, in 2016 the United States Court of Appeals for the District of
Columbia Circuit issued a decision known as United Airlines, Inc. v. FERC, 827 F.3d 122 (2016). In that case, the D.C. Circuit
held that because both the partnership income
tax allowance and the DCF ROE may include investors’ tax costs, permitting both
may
result in a double recovery, and remanded the case back to the Commission for further action.
This week, the Commission took that further action. It issued an order in the SFPP case denying that MLP an income tax allowance. More holistically, the Commission concurrently issued a Revised Policy Statement on Treatment of Income Taxes. In the revised policy statement, the Commission found that "an
impermissible double recovery results from granting a Master Limited Partnership (MLP)
pipeline both an income tax allowance and a return on equity pursuant to the discounted
cash flow methodology."
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Showing posts with label rates. Show all posts
Showing posts with label rates. Show all posts
FERC acts on 2017 tax cuts
Monday, March 19, 2018
Federal utility regulators have taken a portfolio of actions in response to recent changes to U.S. tax law which reduced the tax rates applicable to many electric utilities and pipeline companies. Some rates for use of infrastructure will be reduced automatically, while regulators prompted others to explain why they should not be reduced to reflect the tax law changes. At the same time, regulators have opened an inquiry and proposed a rulemaking to address further aspects of the 2017 federal tax law change.
Late last year, Congress enacted the Tax Cuts and Jobs Act of 2017. That law amended U.S. tax law in a variety of ways. Among other things, the 2017 tax law changes reduced the federal corporate income tax rate from a maximum 35 percent to a flat 21 percent rate, effective January 1, 2018.
Many electric utilities and natural gas and oil pipeline companies stand to benefit from this tax reduction in the form of reduced income tax expense going forward, as well as a reduction in accumulated deferred income taxes on the books of rate-regulated companies. Where tax expense decreases, so does the cost of service.
Rates for use of some federally regulated energy infrastructure are set based on cost of service. On March 15, 2018, the Federal Energy Regulatory Commission took a series of actions to address the effect of the tax law changes on its regulated industries including electric transmission companies, interstate natural gas pipelines, and oil pipelines. According to the Commission, its actions “recognize the specific regulatory and operating parameters that must be addressed differently for each of the industries it regulates.”
Transmission rates for most FERC-regulated utilities automatically adjust with changes in the tax rates based on a formula whose inputs are updated annually or on some other regular cycle. For these utilities, a reduction in corporate income tax means a reduction in rates, although the ratemaking process means there can be a lag in time before rate reductions take effect.
But in some cases, utility tariffs provide for rates are either stated as a fixed number, or the formula includes a fixed tax rate. The Commission identified 48 companies whose transmission tariffs specifically reference tax rates of 35 percent. In a pair of show-cause orders issued under the Federal Power Act -- one for utilities with stated rates, and one for utilities with formula rates referencing 35 percent -- the Commission directed these companies to propose revisions to their transmission rates or show why they should not do so. It also issued two waivers allowing certain utilities mid-year rate adjustments to reflect the new tax law.
Interstate natural gas pipelines typically have stated rates for their services. These rates are approved by the Commission in a rate proceeding under Natural Gas Act sections 4 or 5 and remain in effect until changed in a subsequent section 4 or 5 proceeding. To revise its practices with respect to natural gas pipelines, the Commission issued a Notice of Proposed Rulemaking that would allow it determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction and the Commission’s recently revised policies on income tax allowance. Under the rule proposed by the Commission, interstate pipelines would need to file a one-time report called “FERC Form No. 501-G” describing the rate effect of these changes. In addition to filing the one-time report, each pipeline would have four options: a pro rata rate reduction, a rate settlement or case, an explanation why no rate change is needed, or merely filing the FERC report and letting the Commission decide if further action is required.
While cost-of-service ratemaking typically applies to public utilities and interstate natural gas pipelines, most oil pipelines set their rates using indexing. With respect to oil pipelines regulated by the FERC, the Commission said it will address tax changes in the 2020 five-year review of the oil pipeline index level.
Concurrently, the Commission opened an inquiry into the effect of the Tax Cuts and Jobs Act of 2017 on all jurisdictional rates, including whether the Commission should address certain changes relating to accumulated deferred income taxes and bonus depreciation. In a presentation to the Commission, staff described this Notice of Inquiry as "a vehicle to help the Commission build a record to determine whether additional action is needed."
In a separate policy statement and order issued on March 15, the Commission revised its policies to disallow income tax allowance cost recovery in MLP pipeline rates.
Late last year, Congress enacted the Tax Cuts and Jobs Act of 2017. That law amended U.S. tax law in a variety of ways. Among other things, the 2017 tax law changes reduced the federal corporate income tax rate from a maximum 35 percent to a flat 21 percent rate, effective January 1, 2018.
Many electric utilities and natural gas and oil pipeline companies stand to benefit from this tax reduction in the form of reduced income tax expense going forward, as well as a reduction in accumulated deferred income taxes on the books of rate-regulated companies. Where tax expense decreases, so does the cost of service.
Rates for use of some federally regulated energy infrastructure are set based on cost of service. On March 15, 2018, the Federal Energy Regulatory Commission took a series of actions to address the effect of the tax law changes on its regulated industries including electric transmission companies, interstate natural gas pipelines, and oil pipelines. According to the Commission, its actions “recognize the specific regulatory and operating parameters that must be addressed differently for each of the industries it regulates.”
Transmission rates for most FERC-regulated utilities automatically adjust with changes in the tax rates based on a formula whose inputs are updated annually or on some other regular cycle. For these utilities, a reduction in corporate income tax means a reduction in rates, although the ratemaking process means there can be a lag in time before rate reductions take effect.
But in some cases, utility tariffs provide for rates are either stated as a fixed number, or the formula includes a fixed tax rate. The Commission identified 48 companies whose transmission tariffs specifically reference tax rates of 35 percent. In a pair of show-cause orders issued under the Federal Power Act -- one for utilities with stated rates, and one for utilities with formula rates referencing 35 percent -- the Commission directed these companies to propose revisions to their transmission rates or show why they should not do so. It also issued two waivers allowing certain utilities mid-year rate adjustments to reflect the new tax law.
Interstate natural gas pipelines typically have stated rates for their services. These rates are approved by the Commission in a rate proceeding under Natural Gas Act sections 4 or 5 and remain in effect until changed in a subsequent section 4 or 5 proceeding. To revise its practices with respect to natural gas pipelines, the Commission issued a Notice of Proposed Rulemaking that would allow it determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction and the Commission’s recently revised policies on income tax allowance. Under the rule proposed by the Commission, interstate pipelines would need to file a one-time report called “FERC Form No. 501-G” describing the rate effect of these changes. In addition to filing the one-time report, each pipeline would have four options: a pro rata rate reduction, a rate settlement or case, an explanation why no rate change is needed, or merely filing the FERC report and letting the Commission decide if further action is required.
While cost-of-service ratemaking typically applies to public utilities and interstate natural gas pipelines, most oil pipelines set their rates using indexing. With respect to oil pipelines regulated by the FERC, the Commission said it will address tax changes in the 2020 five-year review of the oil pipeline index level.
Concurrently, the Commission opened an inquiry into the effect of the Tax Cuts and Jobs Act of 2017 on all jurisdictional rates, including whether the Commission should address certain changes relating to accumulated deferred income taxes and bonus depreciation. In a presentation to the Commission, staff described this Notice of Inquiry as "a vehicle to help the Commission build a record to determine whether additional action is needed."
In a separate policy statement and order issued on March 15, the Commission revised its policies to disallow income tax allowance cost recovery in MLP pipeline rates.
Maine Gov. LePage's 2018 State of the State and energy policy
Tuesday, February 13, 2018
Maine Governor Paul R. LePage delivered his final State of the State address this evening. Here's a recap of some of his remarks on energy policy in previous speeches of that sort.
Nevertheless, the Bangor Daily News reports that his remarks as delivered did address energy, calling for lower energy prices.
- In 2012, Governor LePage described Maine’s high energy costs as "one of the largest inhibitors, if not the biggest obstacle to job creation." He advocated an energy policy encompassing "all forms of energy."
- Energy did not appear in his 2013 speech, according to a transcript provided by the Portland Press Herald.
- In 2014, Governor LePage noted that "heating and electricity costs remain a major obstacle," with homeowners spending nearly double the national average on heating, and high electricity costs posting challenges to attracting business. He described efforts to expand natural gas pipeline capacity from Pennsylvania, and to connect to clean energy resources in Quebec.
- In 2015, Governor LePage used his speech to argue for lower electricity rates and home heating costs, as well as changes to Maine’s renewable energy policies.
- In 2016, Governor LePage released his speech in the form of a letter to the state legislature. As in previous speeches, his 2016 letter mentioned energy issues as a focus for -- or obstacle to -- economic development. Arguing that Maine's electricity prices are not competitive, he criticized legislative mandates supporting "long-term contracts for above-market rates." He also called for expansion of linear infrastructure like natural gas pipelines into New England and electric transmission lines to hydropower resources in Canada.
- Last year, he returned to delivering the speech to the legislature orally. His 2017 address included a section on energy matters, in which he criticized the Public Utilities Commission's decision to amend its rules governing net energy billing. He called upon lawmakers to agree to lower energy costs, to lower carbon dioxide levels in the most cost-effective manner, and to reduce our demand for oil.
Nevertheless, the Bangor Daily News reports that his remarks as delivered did address energy, calling for lower energy prices.
Maine's energy legislation carryovers from 2017
Wednesday, September 13, 2017
When the First Regular Session of the 128th Maine State Legislature adjourned earlier this year, its committees reserved a list of bills for further debate in 2018. A list of these carryover bills published by the legislative information office includes 16 bills carried over by the Joint Standing Committee on Energy, Utilities, and Technology. While new legislation may be proposed in the legislature's second session, the committee's work in 2018 will include action on these carried-over bills.
Here's an excerpt from the list of bills carried over, focused on the Energy, Utilities, and Technology committee:
Here's an excerpt from the list of bills carried over, focused on the Energy, Utilities, and Technology committee:
- LD 131, An Act To Protect the Biomass Industry
- LD 140, An Act To Authorize a General Fund Bond Issue To Support Entrepreneurial Activity, Attract Business and Enhance Demographic In-migration by Investing in High-speed Broadband Infrastructure and To Amend the Law Governing the Municipal Gigabit Broadband Network Access Fund
- LD 257, An Act To Enable Municipalities Working with Utilities To Establish Microgrids
- LD 260, An Act to Create the Maine Energy Office
- LD 532, An Act to Remove the 100-megawatt Limit on Hydroelectric Generators under the Renewable Resources Laws
- LD 822, An Act to Ensure Fairness among Large Consumers of Natural Gas
- LD 1176, An Act To Ensure the Safety of Low-income Persons Who Are Deaf and Who Use Video and Captioned Phones by Providing Equitable Access to the Internet
- LD 1224, An Act To Allow for Greater Energy Competition in Maine by Amending the Law Governing Electric Generation or Generation-related Assets by Affiliates
- LD 1372, An Act To Increase Broadband Access for Rural Communities
- LD 1373, An Act To Protect and Expand Access to Solar Power in Maine
- LD 1444, An Act Regarding Large-scale Community Solar Procurement
- LD 1472, An Act To Lower the Costs of Broadband Service by Coordinating the Installation of Broadband Infrastructure
- LD 1487, An Act To Control Electricity Transmission Costs through the Development of Nontransmission Alternatives
- LD 1515, An Act To Reduce Electric Rates for Maine Businesses by Amending the Laws Governing Spending from the Regional Greenhouse Gas Initiative Trust Fund
- LD 1610, An Act To Protect Privacy of Online Customer Personal Information
- LD 1632, An Act To Establish the Manufacturing Jobs Energy Program
Montana to study customer-generator costs, benefits
Thursday, June 22, 2017
Montana utility regulators are preparing to study the costs and benefits of distributed solar energy projects and other customer-generators. The results could reshape the way net-metered customers are charged for electric service, including the creation of a separate service classification and rates for customer-generators.
Earlier this year, the Montana legislature enacted House Bill 219, a law requiring utility NorthWestern Corp. to "conduct a study of the costs and benefits of customer-generators," for submission to the state Public Service Commission to inform future ratemaking. The law allowed the Commission to establish "minimum information requirements" for inclusion in the study.
On June 16, 2017, the Commission posted a Notice of Opportunity to Comment on potential benefit and cost elements and study questions. That notice identified categories of potential benefits including avoided energy costs, avoided capacity costs, avoided transmission and distribution capacity costs, avoided system losses, avoided renewable portfolio standard compliance costs, avoided environmental compliance costs, market price suppression effects, avoided risk, avoided grid support services costs, avoided outages costs, and non-energy benefits. It also identified categories of potential costs, including reduced revenue, administrative costs, interconnection, integration, and cost shifts in production, transmission, and distribution.
The Commission's notice also posed a series of questions relevant to cost-benefit studies, including:
Earlier this year, the Montana legislature enacted House Bill 219, a law requiring utility NorthWestern Corp. to "conduct a study of the costs and benefits of customer-generators," for submission to the state Public Service Commission to inform future ratemaking. The law allowed the Commission to establish "minimum information requirements" for inclusion in the study.
On June 16, 2017, the Commission posted a Notice of Opportunity to Comment on potential benefit and cost elements and study questions. That notice identified categories of potential benefits including avoided energy costs, avoided capacity costs, avoided transmission and distribution capacity costs, avoided system losses, avoided renewable portfolio standard compliance costs, avoided environmental compliance costs, market price suppression effects, avoided risk, avoided grid support services costs, avoided outages costs, and non-energy benefits. It also identified categories of potential costs, including reduced revenue, administrative costs, interconnection, integration, and cost shifts in production, transmission, and distribution.
The Commission's notice also posed a series of questions relevant to cost-benefit studies, including:
- What, if any, assumptions regarding the adoption rate of solar or other net metering technologies should the Commission specify?
- What, if any, time frame for calculating benefits and costs should the Commission specify (e.g., 10 years, 20 years, etc.)?
- What, if any, assumptions regarding utility rates should the Commission specify (e.g., rate of increase, changes in rate design (time-of-use, other))?
- What, if any, methodology for cost-effectiveness tests should the Commission specify (e.g., standard practice manual or the Cost Benefit Framework developed by the Electric Power Research Institute)?
- What cost-effectiveness perspective(s) should the Commission require be evaluated (e.g., societal, utility/program administrator, ratepayer, participant)?
- Should the Commission specify the generating resource avoided by net-metered systems? If so, what generating unit should be used?
- Should the Commission specify a particular locational attribute that counts as either a benefit or cost adder/subtractor?
- What, if any, other compensation approaches in addition to net metering should be assessed in the study NorthWestern is required to conduct?
FERC electric storage policy statement
Monday, January 23, 2017
U.S. energy regulators have issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates. The Federal Energy Regulatory Commission's January 19, 2017 policy statement on storage provides insight into how the Commission views its role in regulating the rates at which energy storage would be compensated -- but was accompanied by a dissenting view expressed by Commissioner LaFleur. The result is a mix of both greater certainty and continued debate.
Electricity storage is a growing industry, both in terms of installed capacity and its capability to flexibly support the grid. Today's electric storage resources can both charge and discharge electricity to and from the grid. Moreover they can provide various services to multiple entities -- for example, consumers, grid operators, or transmission and distribution utilities -- and can switch nearly instantaneously between modes of operation or services provided. In these ways, electric storage resources share some functions of consumer load, generation, transmission, and distribution.
Some of these functions -- e.g. sales of electric energy at wholesale in an organized market -- may be compensated at market-based rates. But other functions of energy storage could be compensated at cost-based rates under federal law -- perhaps functioning as a transmission asset, compensated through transmission rates. Thus it's possible that a particular energy storage resource -- think a battery attached to the electric grid, perhaps sited at a factory or other consumer's location -- might be compensated for its operations under both cost-based and market-based rates.
This is a good thing, according to the Federal Energy Regulatory Commission. According to the January 19, 2017 policy statement, "Enabling electric storage resources to provide multiple services (including both cost-based and market-based services) ensures that the full capabilities of these resources can be realized, thereby maximizing their efficiency and value for the system and to consumers."
But previous proceedings before the Federal Energy Regulatory Commission have exposed some concerns about allowing electric storage resources to recover costs through both cost-based and market-based rates concurrently. As described by the Commission, these include "double recovery of costs to the detriment of cost-based ratepayers, potential for adverse competitive impacts in wholesale electric markets to the detriment of other competitors, and the need for independence of regional grid operators from market participants."
With respect to utilities subject to its jurisdiction, the Commission's recent policy statement, "Utilitzation of Electric Storage Resources for Multiple Services When Receiving Cost-Based Rate Recovery," provides guidance regarding these issues. It details possible approaches for avoiding double recovery of costs. The Commission notes that with regard to adverse market impacts, it "is not convinced there will be a detriment to other market competitors." The policy statement also offers guidance on how grid operators and electric storage owners or operators should interact, to ensure independence as required by Commission policy.
Commissioner LaFleur issued a dissenting opinion, while nevertheless calling storage "an important and promising resource that warrants Commission attention to ensure that our markets are appropriately adapted to recognize storage’s unique characteristics and contributions." While expressing an openness "to potential structures that compensate storage providing transmission service at a cost-based rate while participating in the wholesale markets", she expressed concern "about the broad rationale for this approach put forth in the Policy Statement," which she called "both flawed in its conclusions and premature in its timing." In particular her dissent focused on what she described as "the Policy Statement’s sweeping conclusions about the potential impacts of multiple payment streams on pricing in wholesale electric markets" -- and whether it might have implications for resources other than storage that receive multiple payment streams. She also disagreed with the Commission's decision to issue the policy statement separate from its pending Notice of Proposed Rulemaking on the participation of electric storage in wholesale markets.
Both the majority policy statement and Commissioner LaFleur's dissent shed light on how the Commission approaches energy storage rate issues. Storage seems universally considered worth investigating or supporting, but disagreement remains within the Commission with respect to some aspects of how storage resources should be compensated (as well as procedural issues related to the Commission's consideration of these questions). Nevertheless the policy statement does provide guidance and clarification into how a majority of the Commission views the compensation of storage resources under both cost- and market-based rate structures -- while also framing future discussions over how storage resources will be integrated into markets.
Electricity storage is a growing industry, both in terms of installed capacity and its capability to flexibly support the grid. Today's electric storage resources can both charge and discharge electricity to and from the grid. Moreover they can provide various services to multiple entities -- for example, consumers, grid operators, or transmission and distribution utilities -- and can switch nearly instantaneously between modes of operation or services provided. In these ways, electric storage resources share some functions of consumer load, generation, transmission, and distribution.
Some of these functions -- e.g. sales of electric energy at wholesale in an organized market -- may be compensated at market-based rates. But other functions of energy storage could be compensated at cost-based rates under federal law -- perhaps functioning as a transmission asset, compensated through transmission rates. Thus it's possible that a particular energy storage resource -- think a battery attached to the electric grid, perhaps sited at a factory or other consumer's location -- might be compensated for its operations under both cost-based and market-based rates.
This is a good thing, according to the Federal Energy Regulatory Commission. According to the January 19, 2017 policy statement, "Enabling electric storage resources to provide multiple services (including both cost-based and market-based services) ensures that the full capabilities of these resources can be realized, thereby maximizing their efficiency and value for the system and to consumers."
But previous proceedings before the Federal Energy Regulatory Commission have exposed some concerns about allowing electric storage resources to recover costs through both cost-based and market-based rates concurrently. As described by the Commission, these include "double recovery of costs to the detriment of cost-based ratepayers, potential for adverse competitive impacts in wholesale electric markets to the detriment of other competitors, and the need for independence of regional grid operators from market participants."
With respect to utilities subject to its jurisdiction, the Commission's recent policy statement, "Utilitzation of Electric Storage Resources for Multiple Services When Receiving Cost-Based Rate Recovery," provides guidance regarding these issues. It details possible approaches for avoiding double recovery of costs. The Commission notes that with regard to adverse market impacts, it "is not convinced there will be a detriment to other market competitors." The policy statement also offers guidance on how grid operators and electric storage owners or operators should interact, to ensure independence as required by Commission policy.
Commissioner LaFleur issued a dissenting opinion, while nevertheless calling storage "an important and promising resource that warrants Commission attention to ensure that our markets are appropriately adapted to recognize storage’s unique characteristics and contributions." While expressing an openness "to potential structures that compensate storage providing transmission service at a cost-based rate while participating in the wholesale markets", she expressed concern "about the broad rationale for this approach put forth in the Policy Statement," which she called "both flawed in its conclusions and premature in its timing." In particular her dissent focused on what she described as "the Policy Statement’s sweeping conclusions about the potential impacts of multiple payment streams on pricing in wholesale electric markets" -- and whether it might have implications for resources other than storage that receive multiple payment streams. She also disagreed with the Commission's decision to issue the policy statement separate from its pending Notice of Proposed Rulemaking on the participation of electric storage in wholesale markets.
Both the majority policy statement and Commissioner LaFleur's dissent shed light on how the Commission approaches energy storage rate issues. Storage seems universally considered worth investigating or supporting, but disagreement remains within the Commission with respect to some aspects of how storage resources should be compensated (as well as procedural issues related to the Commission's consideration of these questions). Nevertheless the policy statement does provide guidance and clarification into how a majority of the Commission views the compensation of storage resources under both cost- and market-based rate structures -- while also framing future discussions over how storage resources will be integrated into markets.
Emera Maine proposes Swans Island Electric Coop acquisition
Thursday, September 1, 2016
Maine utility Emera Maine and Swan's Island Electric Cooperative have asked the Maine Public Utilities Commission for approval of Emera Maine's proposed acquisition of the island cooperative. The electric companies say reducing electric rates for consumers is the motivation.
Swan's Island Electric Cooperative is a member-owned rural electric cooperative incorporated in 1949. The cooperative provides electric service to approximately 560 meters in the island communities of Swan's Island and Frenchboro. It receives electricity from the mainland Emera Maine system, via undersea cables running from Mount Desert Island.
In a petition filed September 1, Emera Maine and the cooperative and described a proposed transaction through which Emera Maine would acquire most of Swan's Island Electric Cooperative's assets, acquire all of its service territory, and provide electric service to all Swan's Island and Frenchboro customers. Swan's Island Electric Cooperative would cease providing utility service, wind up its affairs, and formally dissolve the Cooperative.
The petition states that the "primary benefit of the proposed transaction is that Swan's Island and Frenchboro ratepayers will receive immediate and substantial rate relief." According to the petition, the costs of providing electricity to a remote island and small cooperative membership have led to high electricity rates for customers of the cooperative.
The petition notes that Swan's Island customers currently pay delivery charges of 12.343 cents per kilowatt hour and Frenchboro customers pay 15.917 cents per kilowatt hour. Fixed meter charges add another $46.84 per month for Swan's Island customers (or $48.26 for Frenchboro.) The petition contrasts these rates to "a typical residential customer in Emera's Bangor Hydro District", with a delivery charge of 10.770 cents per kilowatt hour and a minimum charge of $7.48 per month.
According to the petition, the cooperative's high rates prompted members to investigate the possibility of a merger with Emera. This led to the August 31, 2016 execution of an Asset Purchase Agreement, under which Emera will purchase the bulk of the cooperative's assets, acquire its service territory and provide service to its current customers, subject to regulatory approval. According to the petition, 90% of votes by cooperative members supported the transaction.
The petition describes Emera's commitments as including the installation of modern "smart meters" for all new cooperative customers, and notes anticipation that the undersea cables will need replacement "within the next several years at an estimated cost of $3.4 million." Emera points to its experience providing service to remote areas, including the Cranberry Isles.
The transaction requires approval by the Maine Public Utilities Commission. The Commission has docketed it as Docket No. 2016-00209.
Swan's Island Electric Cooperative is a member-owned rural electric cooperative incorporated in 1949. The cooperative provides electric service to approximately 560 meters in the island communities of Swan's Island and Frenchboro. It receives electricity from the mainland Emera Maine system, via undersea cables running from Mount Desert Island.
In a petition filed September 1, Emera Maine and the cooperative and described a proposed transaction through which Emera Maine would acquire most of Swan's Island Electric Cooperative's assets, acquire all of its service territory, and provide electric service to all Swan's Island and Frenchboro customers. Swan's Island Electric Cooperative would cease providing utility service, wind up its affairs, and formally dissolve the Cooperative.
The petition states that the "primary benefit of the proposed transaction is that Swan's Island and Frenchboro ratepayers will receive immediate and substantial rate relief." According to the petition, the costs of providing electricity to a remote island and small cooperative membership have led to high electricity rates for customers of the cooperative.
The petition notes that Swan's Island customers currently pay delivery charges of 12.343 cents per kilowatt hour and Frenchboro customers pay 15.917 cents per kilowatt hour. Fixed meter charges add another $46.84 per month for Swan's Island customers (or $48.26 for Frenchboro.) The petition contrasts these rates to "a typical residential customer in Emera's Bangor Hydro District", with a delivery charge of 10.770 cents per kilowatt hour and a minimum charge of $7.48 per month.
According to the petition, the cooperative's high rates prompted members to investigate the possibility of a merger with Emera. This led to the August 31, 2016 execution of an Asset Purchase Agreement, under which Emera will purchase the bulk of the cooperative's assets, acquire its service territory and provide service to its current customers, subject to regulatory approval. According to the petition, 90% of votes by cooperative members supported the transaction.
The petition describes Emera's commitments as including the installation of modern "smart meters" for all new cooperative customers, and notes anticipation that the undersea cables will need replacement "within the next several years at an estimated cost of $3.4 million." Emera points to its experience providing service to remote areas, including the Cranberry Isles.
The transaction requires approval by the Maine Public Utilities Commission. The Commission has docketed it as Docket No. 2016-00209.
Santee Cooper sets solar standby charge
Wednesday, December 9, 2015
The board of South Carolina's state-owned electric utility has approved a plan to increase retail rates and -- controversially -- add new charges for customers who install solar panels. Santee Cooper is South Carolina's largest power producer, providing electricity for about 2
million people. Its interim rider for distributed generation includes a "standby fee" charged to customers with rooftop solar projects and other customer-sited generation. It also declined to adopt a net metering structure similar to those used by South Carolina's investor owned utilities.
Notably, Santee Cooper says it "supports development of solar power resources". Its Distributed Generation Approach notes that Santee Cooper has generated solar energy for its customers since 2006, including demonstration projects across South Carolina. Santee Cooper buys solar power from sources including the 3-megawatt Colleton Solar Farm. The Colleton project, owned and operated by TIG Sun Energy, is South Carolina's largest solar installation. Santee Cooper also offers its customers blocks of Green Power.
But residential solar projects aren't typically owned by or developed for utilities. From the utility perspective, this means that the costs associated with serving customers with solar generation need to be recovered from ratepayers. But the allocation of those costs among ratepayers is an issue. Should they fall on all consumers equally? Or should a rider or specific charge be added to recover these costs from the consumers who install distributed solar generation?
In Santee Cooper's case, the board approved a new charge, called a “standby fee,’’ on residential customers of $4.40 per month per kilowatt of installed solar capacity. It also elected to use rebates and credits to reward customers for solar generation, instead of a net metering rate. At the same time, the board set the rates for crediting generation at less than its retail rate.
From the utility perspective, it needed to adjust its rates to account for growth in rooftop solar and other distributed generation resources, and to protect customers who don't develop solar projects from unfairly bearing costs imposed by those who do. Cost-shifting is a typical utility concern; the issue is to make sure that the allocation of consumer costs is fairly related to how the costs were incurred.
But from the perspective of advocates for rooftop solar and other distributed generation resources, a "solar fee" would deter people from developing alternative energy projects. Under this view, these fees and rate structure are unnecessary and "penalize customers for exercising their right to use this clean, renewable resource."
Santee Cooper is not alone in considering how to adjust utility rates to handle more rooftop solar projects. But its approach differs from that of South Carolina's largest investor owned utilities, Duke Energy Carolinas and South Carolina Electric and Gas, which have agreed to net energy metering and solar development targets.
How should utility rate design allocate the costs and benefits of connecting distributed solar projects to the grid? How can essential fairness in ratemaking be balanced against policy values like customer choice and renewable energy?
Notably, Santee Cooper says it "supports development of solar power resources". Its Distributed Generation Approach notes that Santee Cooper has generated solar energy for its customers since 2006, including demonstration projects across South Carolina. Santee Cooper buys solar power from sources including the 3-megawatt Colleton Solar Farm. The Colleton project, owned and operated by TIG Sun Energy, is South Carolina's largest solar installation. Santee Cooper also offers its customers blocks of Green Power.
But residential solar projects aren't typically owned by or developed for utilities. From the utility perspective, this means that the costs associated with serving customers with solar generation need to be recovered from ratepayers. But the allocation of those costs among ratepayers is an issue. Should they fall on all consumers equally? Or should a rider or specific charge be added to recover these costs from the consumers who install distributed solar generation?
In Santee Cooper's case, the board approved a new charge, called a “standby fee,’’ on residential customers of $4.40 per month per kilowatt of installed solar capacity. It also elected to use rebates and credits to reward customers for solar generation, instead of a net metering rate. At the same time, the board set the rates for crediting generation at less than its retail rate.
From the utility perspective, it needed to adjust its rates to account for growth in rooftop solar and other distributed generation resources, and to protect customers who don't develop solar projects from unfairly bearing costs imposed by those who do. Cost-shifting is a typical utility concern; the issue is to make sure that the allocation of consumer costs is fairly related to how the costs were incurred.
But from the perspective of advocates for rooftop solar and other distributed generation resources, a "solar fee" would deter people from developing alternative energy projects. Under this view, these fees and rate structure are unnecessary and "penalize customers for exercising their right to use this clean, renewable resource."
Santee Cooper is not alone in considering how to adjust utility rates to handle more rooftop solar projects. But its approach differs from that of South Carolina's largest investor owned utilities, Duke Energy Carolinas and South Carolina Electric and Gas, which have agreed to net energy metering and solar development targets.
How should utility rate design allocate the costs and benefits of connecting distributed solar projects to the grid? How can essential fairness in ratemaking be balanced against policy values like customer choice and renewable energy?
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.
Study quantifies New England distributed generation, growth
Wednesday, June 12, 2013
Distributed generation – small-scale electric generation facilities installed at consumer sites – plays a growing role in the resource mix used to meet society’s needs. Typical distributed generation assets include solar photovoltaic panels and co-generation or combined heat and power units developed at homes and businesses. A study released yesterday found that distributed generation capacity in New England could roughly triple in the next decade – and that regional electric grid operator ISO New England Inc. needs to account for distributed generation in its planning.
As New England’s regional transmission organization, ISO New England plans for and coordinates the development of electric transmission infrastructure. In the past decade, New England ratepayers have spent approximately $5 billion on transmission additions and expansions. ISO New England’s 2012 Regional System Plan calls for the investment of another $6 billion in transmission projects in the coming years. As a result, regional transmission rates roughly tripled between 2006 and 2010, and continue to grow.
ISO New England’s plans are based on its forecasts of future system needs, including anticipated load growth and changes in the electric generation portfolio used to satisfy customer demand. But ISO New England may be underestimating the extent to which non-transmission alternatives like distributed generation can satisfy demand at a lower total cost than transmission line development. According to “Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning”, prepared by Synapse Energy Economics Inc., ISO New England is significantly underestimating the current and potential distributed generation in New England, particularly with respect to solar photovoltaic resources. According to Synapse, “This practice results in the ISO ignoring likely transmission and reliability benefits and overestimating electricity load—with ratepayers being asked to pay for larger, more expensive transmission upgrades than are needed.”
ISO New England predicts that about 800 MW of solar photovoltaic generation will be installed in New England by 2021, but excludes other types of distributed generation from its projection. But Synapse found that over 980 megawatts of distributed generation assets are already installed in the six New England states. By 2021, Synapse predicts that this could grow to over 2,855 MW based on existing policies and development trends.
State policies and the favorable economics of distributed generation projects are driving their adoption on a wider scale than in previous years. For example, after exceeding its previous solar photovoltaic target, Massachusetts recently increased its target to 1,600 MW. Renewable portfolio standards, net metering policies, and feed-in tariffs all contribute to the proliferation of distributed generation, as does a cost differential that makes natural gas-fired cogeneration more cost-effective than burning oil for heating and purchasing electricity in commercial and industrial applications.
Synapse’s report concludes, “It is essential that the ISO stop ignoring the impacts DG resources have on system planning—both their benefits and their challenges. This report provides a reasonable estimate of what the future holds for these resources and makes one thing very clear: assuming that these resources do not exist is unacceptable.”
Whether and how ISO New England and the states take distributed generation into account remains to be seen, but if the trends noted in the Synapse report play out to even a modest degree, non-transmission alternatives such as distributed generation may be able to limit further increases in regional transmission rates.
As New England’s regional transmission organization, ISO New England plans for and coordinates the development of electric transmission infrastructure. In the past decade, New England ratepayers have spent approximately $5 billion on transmission additions and expansions. ISO New England’s 2012 Regional System Plan calls for the investment of another $6 billion in transmission projects in the coming years. As a result, regional transmission rates roughly tripled between 2006 and 2010, and continue to grow.
ISO New England’s plans are based on its forecasts of future system needs, including anticipated load growth and changes in the electric generation portfolio used to satisfy customer demand. But ISO New England may be underestimating the extent to which non-transmission alternatives like distributed generation can satisfy demand at a lower total cost than transmission line development. According to “Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning”, prepared by Synapse Energy Economics Inc., ISO New England is significantly underestimating the current and potential distributed generation in New England, particularly with respect to solar photovoltaic resources. According to Synapse, “This practice results in the ISO ignoring likely transmission and reliability benefits and overestimating electricity load—with ratepayers being asked to pay for larger, more expensive transmission upgrades than are needed.”
ISO New England predicts that about 800 MW of solar photovoltaic generation will be installed in New England by 2021, but excludes other types of distributed generation from its projection. But Synapse found that over 980 megawatts of distributed generation assets are already installed in the six New England states. By 2021, Synapse predicts that this could grow to over 2,855 MW based on existing policies and development trends.
 |
| Synapse Energy Economics, Inc., Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning, at page 19. |
State policies and the favorable economics of distributed generation projects are driving their adoption on a wider scale than in previous years. For example, after exceeding its previous solar photovoltaic target, Massachusetts recently increased its target to 1,600 MW. Renewable portfolio standards, net metering policies, and feed-in tariffs all contribute to the proliferation of distributed generation, as does a cost differential that makes natural gas-fired cogeneration more cost-effective than burning oil for heating and purchasing electricity in commercial and industrial applications.
Synapse’s report concludes, “It is essential that the ISO stop ignoring the impacts DG resources have on system planning—both their benefits and their challenges. This report provides a reasonable estimate of what the future holds for these resources and makes one thing very clear: assuming that these resources do not exist is unacceptable.”
Whether and how ISO New England and the states take distributed generation into account remains to be seen, but if the trends noted in the Synapse report play out to even a modest degree, non-transmission alternatives such as distributed generation may be able to limit further increases in regional transmission rates.
Transmission costs up, energy costs down
Monday, July 2, 2012
The cost of electric transmission and distribution service in Maine is going up, at the same time that the cost of electric energy is going down. What this means has implications not only for Maine but for all societies seeking to reduce the cost of electricity.
The cost of electricity to consumers can generally be broken down into two categories: energy and transmission and distribution service. Electric energy charges represent the cost of the useable electricity that flows through an end-user's meter. Transmission and distribution service charges, sometimes called "wires charges" or "delivery charges", represent the cost of delivering that amount of energy to the consumer.
In many states, vertically-integrated utilities both generate and deliver the energy. Other states have restructured or deregulated their electric generation business; in these states, electric utilities deliver energy produced by non-utility generators. Consumers in restructured states are usually free to select their own competitive electricity provider, whose energy will be delivered over the wires operated by the monopolistic local utility. Because utilities continue to have a duty to serve all customers, if a consumer doesn't choose a competitive generation source, the utility will provide energy through a default service or "standard offer".
Maine is an example of a restructured state. The state Public Utilities Commission regulates transmission and distribution utilities and their rates. Effective July 1, the wires charges for Maine's two largest utilities -- Central Maine Power Co. (CMP) and Bangor Hydro Electric Company (BHE) -- went up. On average, CMP customers' rates show an increase of 7.1% for the delivery portion of the bill; BHE customers' delivery rates increased 4.5%. According to the Maine PUC's press release, the major driving force behind these increases are significant increases in the utilities' federally regulated transmission rates: a 19.6% increase for CMP and a 12% increase for BHE. These transmission rate increases are in turn driven by multi-billion dollar expansions of and upgrades to the New England transmission grid.
At the same time, average energy prices in New England decreased by 7% between 2010 and 2011, largely as a result of cheaper natural gas supplies and reduced demand for electricity. These energy price declines translated into decreases in the standard offer service delivered by these two utilities, about 25% to 35% lower than prices one year ago.
These twin forces -- increased investment in the transmission grid and reduced electric energy costs -- are not unique to Maine, but exert themselves in a number of regions of the United States. One net result of these changes is a shifting of consumer costs away from energy and onto wires charges. The cost of transmission and distribution service thus plays an increasing role in driving customers' electricity costs. Given this shift, efforts to reduce the cost of electricity to consumers may find the most fertile ground in ensuring that transmission development is efficient, and that utility developers earn a rate of return on their investment that is fair, or in federal regulators' terms, "just and reasonable".
The cost of electricity to consumers can generally be broken down into two categories: energy and transmission and distribution service. Electric energy charges represent the cost of the useable electricity that flows through an end-user's meter. Transmission and distribution service charges, sometimes called "wires charges" or "delivery charges", represent the cost of delivering that amount of energy to the consumer.
In many states, vertically-integrated utilities both generate and deliver the energy. Other states have restructured or deregulated their electric generation business; in these states, electric utilities deliver energy produced by non-utility generators. Consumers in restructured states are usually free to select their own competitive electricity provider, whose energy will be delivered over the wires operated by the monopolistic local utility. Because utilities continue to have a duty to serve all customers, if a consumer doesn't choose a competitive generation source, the utility will provide energy through a default service or "standard offer".
Maine is an example of a restructured state. The state Public Utilities Commission regulates transmission and distribution utilities and their rates. Effective July 1, the wires charges for Maine's two largest utilities -- Central Maine Power Co. (CMP) and Bangor Hydro Electric Company (BHE) -- went up. On average, CMP customers' rates show an increase of 7.1% for the delivery portion of the bill; BHE customers' delivery rates increased 4.5%. According to the Maine PUC's press release, the major driving force behind these increases are significant increases in the utilities' federally regulated transmission rates: a 19.6% increase for CMP and a 12% increase for BHE. These transmission rate increases are in turn driven by multi-billion dollar expansions of and upgrades to the New England transmission grid.
At the same time, average energy prices in New England decreased by 7% between 2010 and 2011, largely as a result of cheaper natural gas supplies and reduced demand for electricity. These energy price declines translated into decreases in the standard offer service delivered by these two utilities, about 25% to 35% lower than prices one year ago.
These twin forces -- increased investment in the transmission grid and reduced electric energy costs -- are not unique to Maine, but exert themselves in a number of regions of the United States. One net result of these changes is a shifting of consumer costs away from energy and onto wires charges. The cost of transmission and distribution service thus plays an increasing role in driving customers' electricity costs. Given this shift, efforts to reduce the cost of electricity to consumers may find the most fertile ground in ensuring that transmission development is efficient, and that utility developers earn a rate of return on their investment that is fair, or in federal regulators' terms, "just and reasonable".
July 19, 2011 - Nova Scotia tidal energy, feed-in tariffs and projects
Tuesday, July 19, 2011
Hydrokinetic energy projects are cropping up in Canada just as they are in the U.S. (For a review of hydrokinetic energy, check out last month's entries.) The Bay of Fundy is famous for its tides, among the largest in the world. The Canadian province of Nova Scotia is home to a large portion of this resource. Nova Scotia is also home to an existing tidal power plant: utility Nova Scotia Power's Annapolis Tidal Power Plant. This tidal energy project, which came online in 1984, has a capacity of 20 megawatts and can generally produce between 80 and 100 megawatt-hours per day.
Now, Maine-based Ocean Renewable Power Co. has announced plans with Nova Scotia-based Fundy Tidal Inc. to install underwater hydrokinetic turbines to generate electricity from the Bay of Fundy's tides. The proposal involves the installation of 15 to 20 150-kW turbines in the Petit Passage between Digby Neck and Long Island off western Nova Scotia (map) by 2012.
The new venture, named ORPC Nova Scotia Ltd., plans to benefit from Nova Scotia's feed-in tariff. That program, known as the community-based feed-in tariff or COMFIT, is projected to require utilities to pay qualified tidal projects 65.2 cents per kilowatt-hour for their output. This rate, about six times higher than the typical rate for electricity, is a significant incentive for the development of the province's resources. Additional support is available from the provincial government to assess hydrokinetic and small tidal projects like the Petit Passage project.
This project may be smaller than the 500 MW Passamaquoddy Power Project first proposed in 1919, but it could represent the first commercial deployment of underwater hydrokinetic turbines in the Bay of Fundy, and follows in Nova Scotia's traditions of harvesting the energy of its tides.
 |
| The tide drops out of a tidal marsh near the Back River on Arrowsic Island, Maine. |
Now, Maine-based Ocean Renewable Power Co. has announced plans with Nova Scotia-based Fundy Tidal Inc. to install underwater hydrokinetic turbines to generate electricity from the Bay of Fundy's tides. The proposal involves the installation of 15 to 20 150-kW turbines in the Petit Passage between Digby Neck and Long Island off western Nova Scotia (map) by 2012.
The new venture, named ORPC Nova Scotia Ltd., plans to benefit from Nova Scotia's feed-in tariff. That program, known as the community-based feed-in tariff or COMFIT, is projected to require utilities to pay qualified tidal projects 65.2 cents per kilowatt-hour for their output. This rate, about six times higher than the typical rate for electricity, is a significant incentive for the development of the province's resources. Additional support is available from the provincial government to assess hydrokinetic and small tidal projects like the Petit Passage project.
This project may be smaller than the 500 MW Passamaquoddy Power Project first proposed in 1919, but it could represent the first commercial deployment of underwater hydrokinetic turbines in the Bay of Fundy, and follows in Nova Scotia's traditions of harvesting the energy of its tides.
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