The U.S. federal agency responsible for leasing offshore wind sites on the outer continental shelf has executed its first wind energy research lease, giving Virginia's state energy agency the right to pursue the Virginia Offshore Wind Technology Advancement Project (VOWTAP), a 12-megawatt offshore wind test facility to be located in federal ocean waters.
Offshore wind energy offers the potential to generate large amounts of electricity from a renewable resource, but to date no commercial grid-tied U.S. offshore wind projects are operating. The U.S. Bureau of Ocean Energy Management is responsible for leasing sites on the outer continental shelf for energy projects, including offshore wind and other renewable energy developments. BOEM has auctioned off sites for offshore wind projects off several East Coast states, including Virginia, but had not previously issued a research lease.
On March 24, BOEM announced the execution of a wind energy research lease with the Commonwealth of Virginia’s Department of Mines, Minerals and Energy (DMME). Under research lease OCS-A 0497 (35 pages), the Virginia agency proposes to design, develop and demonstrate a
grid-connected, 12-megawatt offshore wind test facility on the
Outer Continental Shelf off the coast of Virginia, in partnership with a local utility affiliated with Dominion Resources, Inc.
The 30-year lease covers approximately 2,135 acres of sea space east of Virginia Beach, adjacent to the Wind Energy Area leased to Virginia Electric and Power Company (dba Dominion Virginia Power) for commercial development since 2013. The lease describes the project as "a research project to generate energy using wind turbine generators and conduct any associated resource assessment activities, as well as install associated offshore substation platforms, inter-array cables, and subsea export cables." As a research lease, the Virginia agreement does not include any fees
payable from DMME to BOEM "for the purpose of ensuring a fair return for
the use of this lease area."
As is standard for BOEM's offshore wind site leases, the lease itself does not give the lessee the right to build or operate an offshore wind project. Rather, the lease gives the Virginia DMME the exclusive right to submit to BOEM for approval a Site Assessment Plan and a Research Activities Plan, and then to allow a designated operator to conduct whatever activities are described in those plans once they are approved by BOEM.
In this case, DMME has designated Dominion subsidiary Virginia Electric and Power Company as the lease operator. Dominion's partnership with DMME on offshore wind dates back at least to 2012, when the U.S. Department of Energy announced funding awards for seven proposed Offshore Wind Advanced Technology Demonstration Projects. Dominion won one of these
2012 awards, and partnered with DMME
and others to establish VOWTAP. VOWTAP won a second funding award from DOE in 2014 for deployment
activities.
Dominion and DMME have already filed a Research Activities Plan for VOWTAP. With the research lease in hand, the path forward includes approval of that plan and a Site Assessment Plan by BOEM. If the VOWTAP project is built, the data obtained and lessons learned from this project will be made
publicly available and inform the future production of renewable energy
within the adjacent commercial Wind Energy Area leased to Dominion.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Texas small hydro project loses exemption
Wednesday, March 25, 2015
What happens to a proposed hydroelectric project takes longer than anticipated to be built, due to difficulties with project financing and severe flooding? As the developer of a proposed project in Texas recently found out, federal regulators can be lenient up to a point -- but under some circumstances the developer can lose its federal authorization to develop and operate the project.
The A.H. Smith Dam on the San Marcos River in Martindale, Texas was originally constructed in about 1894 to provide mechanical power a cotton gin; later, electric generation was installed, but power production ceased in the 1940s when low wholesale energy prices made operation uneconomic. Modern hydropower facilities rated at 150 kilowatts were installed in 1984, but were ultimately abandoned.
In 2005, developer Hydraco Power, Inc. applied to the Federal Energy Regulatory Commission for an exemption from the licensing requirements of Part I of the Federal Power Act for its proposed A.H. Smith Dam Project. Hydraco's project included refurbishing and restoring the operation of the existing turbine located at the dam's powerhouse, installing a new buried transmission line and a water surface elevation gate in the headpond.
On June 2, 2006, the Commission granted Hydraco an exemption for the project. As a standard condition of exemptions, the Commission retained the right to revoke the exemption if any term or condition was violated. Among the terms was a requirement that Hydraco file within 120 days a
plan and schedule to install the new transmission line and restore the powerhouse, turbine, and trash racks to operating condition, as well as notice that the Commission could terminate the exemption if actual construction of any proposed or required facility had not begun within two years or had not been completed within four years of the date of issuance of the exemption.
Over the next 8 years, Hydraco filed a series of construction plans and schedules, but never completed the project despite obtaining repeated extensions of key deadlines. After multiple prompts by Commission staff to file a revised plan and schedule for restoring project operation or an application to surrender the exemption, the Commission noted that Hydraco either failed to respond or responded by stating that it could not estimate a schedule for restoring project operation because project construction, including major component repairs, was on hold due to lack of funds.
After the Commission issued a public notice in August 2014 stating its intent to terminate the project exemption "due to Hydraco’s longstanding violation of exemption Article 10 and its failure to provide a timeframe for restoring project generation", on November 20, 2014, the Commission issued an Order Terminating Exemption. That order found that "Hydraco has only performed minimal work at the project since obtaining its exemption in 2006 and that it lacks the funding to proceed with the necessary component repairs, including construction of the powerhouse interior and generating unit."
Hydraco filed a request for rehearing of the Order Terminating Exemption. On rehearing, Hydraco asserted that it had reached a financing agreement with a new investor and, consequently, it is ready to perform the work needed to comply with its exemption. Hydraco also objected to the findings that project construction was at a standstill and that Hydraco intended to abandon the project, noting that the Commission should excuse construction delays caused by severe flooding.
Last week, the Commission issued an Order Denying Rehearing in the case. It first noted that Hydraco had not demonstrated that it now has the money needed to bring the project on line. Not only did Hydraco not show evidence of a final financing agreement, but the documents showed a source of only half of the funding needed for project restoration. Second, the Commission noted that Hydraco's recent activities -- regularly inspecting the dam and removing debris from its spillway, trashracks, and grates, securing the site against vandalism and installing lighting, and repairing damage caused by a flood -- are "either maintenance or repair, not project development." Finally, the Commission articulated its "doctrine of implied surrender", which it applies where the entity responsible for the project has, by action or inaction, clearly indicated its intent to abandon the project, but has not filed a surrender application.
With the exemption terminated and Hydraco's request for rehearing denied, the A.H. Smith Dam project faces an uncertain future. On the one hand, the site presumably still offers many of the same values that Hydraco hoped to capture -- use an existing dam, with existing generation facilities, to generate renewable electricity. However, the loss of the FERC exemption means that Hydraco (or any other developer) will have to start the federal hydropower process over if it hopes to redevelop the dam as a hydroelectric generating site.
The case of the A.H. Smith Dam project illustrates a number of themes: interest in restoring existing hydropower infrastructure to generate renewable energy with relatively less environmental impact than newly-built dams, the challenge of securing financing for small hydropower projects -- and perhaps most importantly the value of compliance with FERC hydropower rules.
The A.H. Smith Dam on the San Marcos River in Martindale, Texas was originally constructed in about 1894 to provide mechanical power a cotton gin; later, electric generation was installed, but power production ceased in the 1940s when low wholesale energy prices made operation uneconomic. Modern hydropower facilities rated at 150 kilowatts were installed in 1984, but were ultimately abandoned.
In 2005, developer Hydraco Power, Inc. applied to the Federal Energy Regulatory Commission for an exemption from the licensing requirements of Part I of the Federal Power Act for its proposed A.H. Smith Dam Project. Hydraco's project included refurbishing and restoring the operation of the existing turbine located at the dam's powerhouse, installing a new buried transmission line and a water surface elevation gate in the headpond.
On June 2, 2006, the Commission granted Hydraco an exemption for the project. As a standard condition of exemptions, the Commission retained the right to revoke the exemption if any term or condition was violated. Among the terms was a requirement that Hydraco file within 120 days a
plan and schedule to install the new transmission line and restore the powerhouse, turbine, and trash racks to operating condition, as well as notice that the Commission could terminate the exemption if actual construction of any proposed or required facility had not begun within two years or had not been completed within four years of the date of issuance of the exemption.
Over the next 8 years, Hydraco filed a series of construction plans and schedules, but never completed the project despite obtaining repeated extensions of key deadlines. After multiple prompts by Commission staff to file a revised plan and schedule for restoring project operation or an application to surrender the exemption, the Commission noted that Hydraco either failed to respond or responded by stating that it could not estimate a schedule for restoring project operation because project construction, including major component repairs, was on hold due to lack of funds.
After the Commission issued a public notice in August 2014 stating its intent to terminate the project exemption "due to Hydraco’s longstanding violation of exemption Article 10 and its failure to provide a timeframe for restoring project generation", on November 20, 2014, the Commission issued an Order Terminating Exemption. That order found that "Hydraco has only performed minimal work at the project since obtaining its exemption in 2006 and that it lacks the funding to proceed with the necessary component repairs, including construction of the powerhouse interior and generating unit."
Hydraco filed a request for rehearing of the Order Terminating Exemption. On rehearing, Hydraco asserted that it had reached a financing agreement with a new investor and, consequently, it is ready to perform the work needed to comply with its exemption. Hydraco also objected to the findings that project construction was at a standstill and that Hydraco intended to abandon the project, noting that the Commission should excuse construction delays caused by severe flooding.
Last week, the Commission issued an Order Denying Rehearing in the case. It first noted that Hydraco had not demonstrated that it now has the money needed to bring the project on line. Not only did Hydraco not show evidence of a final financing agreement, but the documents showed a source of only half of the funding needed for project restoration. Second, the Commission noted that Hydraco's recent activities -- regularly inspecting the dam and removing debris from its spillway, trashracks, and grates, securing the site against vandalism and installing lighting, and repairing damage caused by a flood -- are "either maintenance or repair, not project development." Finally, the Commission articulated its "doctrine of implied surrender", which it applies where the entity responsible for the project has, by action or inaction, clearly indicated its intent to abandon the project, but has not filed a surrender application.
With the exemption terminated and Hydraco's request for rehearing denied, the A.H. Smith Dam project faces an uncertain future. On the one hand, the site presumably still offers many of the same values that Hydraco hoped to capture -- use an existing dam, with existing generation facilities, to generate renewable electricity. However, the loss of the FERC exemption means that Hydraco (or any other developer) will have to start the federal hydropower process over if it hopes to redevelop the dam as a hydroelectric generating site.
The case of the A.H. Smith Dam project illustrates a number of themes: interest in restoring existing hydropower infrastructure to generate renewable energy with relatively less environmental impact than newly-built dams, the challenge of securing financing for small hydropower projects -- and perhaps most importantly the value of compliance with FERC hydropower rules.
FERC 2014 State of the Markets report
Monday, March 23, 2015
U.S. energy markets overseen by the Federal Energy Regulatory Commission in 2014 were impacted by extreme weather and changes in the mix of electric generation resources, according to a report by Commission staff.
The 2014 State of the Markets report issued on March 19 by FERC's Office of Enforcement’s Division of Energy Market Oversight presents Commission's staff’s assessment of recent developments in natural gas, electric, and other energy markets.
Extreme cold temperatures in the first quarter of 2014 affected natural gas infrastructure and power markets across the country. The price of natural gas in the U.S. reached record high levels, driving corresponding spikes in the price of electricity. For example, the price of natural gas at the Transco Zone 6 Non-NY pricing point hit $123/MMBtu in January -- about 33 times higher than the average 2013 U.S. price. Largely due to these price spikes, the spot natural gas price at the Henry Hub pricing point averaged $4.32/MMBtu in 2014, a 16% increase over 2013.
Meanwhile, natural gas and renewable resources continued to displace coal as a fuel for electric power generation. Total U.S. generating capacity increased 10.8 GW in 2014, with natural gas and renewable projects representing the bulk of new capacity. At the same time, utilities retired coal-fired power plants, continuing a trend that started in 2012. Commission staff projects continued coal retirements in 2015, particularly after the April effective date of additional air emissions regulations imposed by the Environmental Protection Agency's Mercury and Air Toxics Standards.
FERC's 2014 State of the Markets report also provides a quick look at 2015 year-to-date market performance. Wholesale electricity prices rose again this winter, although not as sharply as in the first quarter of 2014. FERC staff's report suggests factors helping to moderate winter prices included better cold-weather preparation of assets, programs like ISO New England's Winter Reliability Program, better coordination between operators of electric transmission and natural gas pipelines, record high levels of natural gas production, the development of new pipeline infrastructure, and low oil prices.
More solar faster, predicts New England grid operator
Tuesday, March 17, 2015
New England will likely see even more solar photovoltaic energy projects over the next decade than was previously projected, according to the latest draft forecast by the operator of New England's electric grid.
To help plan for future needs, grid operator ISO New England, Inc. is developing an updated forecast of solar photovoltaic project development in New England. In 2014, ISO New England developed its first multistate forecast of PV capacity growth. It based its 2014 PV forecast heavily on development goals articulated as policies in the six New England states.
ISO New England is now updating that forecast for 2015. Its draft 2015 Solar PV Forecast, released on February 27, notes that PV development is happening more rapidly than was previously projected. Using updated historical data, it acknowledges that through 2014, 40% more solar capacity was developed in the region than it previously estimated. As a result of this faster-than-expected growth, the draft now predicts a higher level of cumulative photovoltaic project development through 2023.
Perhaps more significantly for the solar boom, ISO-NE's draft 2015 forecast also frontloads more new project capacity into 2015 and 2016, while decreasing the amount predicted to be newly developed in later years. While last year's forecast also predicts more incremental solar capacity will be developed in each of the next three years than in later years, the frontloading is more prominent in the draft 2015 forecast.
The draft 2015 forecast projects that 2,138.8 megawatts of solar photovoltaic projects will be developed in New England by 2024. This capacity is stated as an alternating current nameplate rating, even though photovoltaic cells essentially generate direct current electricity. The study derates direct current capacity to alternating current with an 83% array-to-inverter ratio, so this implies an even higher number of megawatts if stated as direct current capacity, as most solar projects are described.
The draft 2015 forecast projects that these solar photovoltaic projects will give rise to a summer seasonal claimed capability of 748.6 megawatts.
ISO New England did not include in its draft 2015 PV forecast any update to its forecast of how much energy these projects would produce. Instead it suggests that it must first finalize its forecast of installed photovoltaic capacity, and can then estimate the energy production associated with the forecast. The report does repeat 2014's forecast of energy as illustrative, keeping in mind that actual amounts of energy generated from solar photovoltaic capacity in New England will likely be higher if capacity forecasts are revised upward as is proposed in this draft.
The 2015 draft PV report is now under review by ISO New England's Distributed Generation Forecast Working Group. That group next meets on April 14, where the final draft forecast will be presented.
 |
| Solar photovoltaic panels on the roof of a Massachusetts home. |
To help plan for future needs, grid operator ISO New England, Inc. is developing an updated forecast of solar photovoltaic project development in New England. In 2014, ISO New England developed its first multistate forecast of PV capacity growth. It based its 2014 PV forecast heavily on development goals articulated as policies in the six New England states.
ISO New England is now updating that forecast for 2015. Its draft 2015 Solar PV Forecast, released on February 27, notes that PV development is happening more rapidly than was previously projected. Using updated historical data, it acknowledges that through 2014, 40% more solar capacity was developed in the region than it previously estimated. As a result of this faster-than-expected growth, the draft now predicts a higher level of cumulative photovoltaic project development through 2023.
Perhaps more significantly for the solar boom, ISO-NE's draft 2015 forecast also frontloads more new project capacity into 2015 and 2016, while decreasing the amount predicted to be newly developed in later years. While last year's forecast also predicts more incremental solar capacity will be developed in each of the next three years than in later years, the frontloading is more prominent in the draft 2015 forecast.
The draft 2015 forecast projects that 2,138.8 megawatts of solar photovoltaic projects will be developed in New England by 2024. This capacity is stated as an alternating current nameplate rating, even though photovoltaic cells essentially generate direct current electricity. The study derates direct current capacity to alternating current with an 83% array-to-inverter ratio, so this implies an even higher number of megawatts if stated as direct current capacity, as most solar projects are described.
The draft 2015 forecast projects that these solar photovoltaic projects will give rise to a summer seasonal claimed capability of 748.6 megawatts.
ISO New England did not include in its draft 2015 PV forecast any update to its forecast of how much energy these projects would produce. Instead it suggests that it must first finalize its forecast of installed photovoltaic capacity, and can then estimate the energy production associated with the forecast. The report does repeat 2014's forecast of energy as illustrative, keeping in mind that actual amounts of energy generated from solar photovoltaic capacity in New England will likely be higher if capacity forecasts are revised upward as is proposed in this draft.
The 2015 draft PV report is now under review by ISO New England's Distributed Generation Forecast Working Group. That group next meets on April 14, where the final draft forecast will be presented.
Controversy over renewable energy claims
Thursday, March 5, 2015
If an electric utility generates power from renewable resources and sells renewable energy certificates representing the renewable attributes of that energy, can it still call the underlying power "renewable"? No, according to the U.S. Federal Trade Commission.
While this question may seem metaphysical, it arises from the structure of most U.S. renewable energy markets. Most states have adopted renewable portfolio standards, which require utilities and competitive electricity suppliers to source some of their power from renewable resources. In most cases, utilities and suppliers can satisfy this requirement by using renewable energy certificates or credits known as RECs. While each state's program differs, these RECs typically represent the renewable attributes of electric energy -- the right to claim that energy is renewable -- but are distinct from that underlying energy. As a result, a renewable generator can sell RECs to one buyer and the underlying energy to another.
Vermont utility Green Mountain Power Corporation recently found itself at the center of controversy over its claims regarding renewable energy. The utility owns and is involved with a variety of renewable energy generation projects in Vermont, including wind and solar projects. It sells energy produced from these projects to Vermont customers, while simultaneously selling some of the RECs generated by these sources to out of state utilities.
In 2014, concerns over "double counting" of renewable energy attributes led Connecticut to ban the use of RECs from renewable generation that also is counted toward another state’s renewable goals for meeting Connecticut's requirements, and REC marketer NextEra Energy to notify New England market participants that it would no longer buy Vermont RECs.
On September 15, 2014, a group of petitioners asked the Federal Trade Commission to investigate Vermont utility Green Mountain Power Corporation's claims that it is providing its customers with electricity from renewable sources such as commercial wind and solar projects, given its separate sale of the RECs to out of state utilities. The Federal Trade Commission regulates claims about the environmental impacts of commerce under Section 5 of the Federal Trade Commission Act, including claims regarding the production, sale, and use of renewable energy. In their complaint, the petitioners claimed that "Vermont customers are being misled into thinking that they are buying 'renewable energy,' when in fact what they are getting is 'null' electricity consisting of a mix of fossil fuel, nuclear, gas and other 'brown' sources of electricity from the regional grid."
The FTC responded to this petition in February 2015 by issuing a letter to Green Mountain Power's counsel expressing concern that the utility might have created confusion for its customers about the renewable attributes of the power they purchased by not “clearly and consistently communicating” that it sells RECs for most of its renewable energy-generating facilities to entities outside Vermont. In the letter, the FTC said that it had not found that any Green Mountain Power statements violated the Federal Trade Commission Act. However, the Commission urged Green Mountain Power in the future to prevent any confusion by clearly communicating the implications of its REC sales for Vermont customers and REC purchasers.
The FTC letter represents the latest salvo in efforts to regulate claims regarding the production, sale, and use of renewable energy. To help marketers avoid making deceptive environmental claims, for over 20 years the FTC has issued "Green Guides" providing its administrative interpretation of the law. The Green Guides outline general principles that apply to all environmental marketing claims and provide guidance regarding many specific environmental benefit claims, including renewable energy claims. The Green Guides, as well as the recent FTC letter, illustrate the importance of caution in making claims about renewable energy in business activities.
 |
| Solar panels in the Utah desert. |
While this question may seem metaphysical, it arises from the structure of most U.S. renewable energy markets. Most states have adopted renewable portfolio standards, which require utilities and competitive electricity suppliers to source some of their power from renewable resources. In most cases, utilities and suppliers can satisfy this requirement by using renewable energy certificates or credits known as RECs. While each state's program differs, these RECs typically represent the renewable attributes of electric energy -- the right to claim that energy is renewable -- but are distinct from that underlying energy. As a result, a renewable generator can sell RECs to one buyer and the underlying energy to another.
Vermont utility Green Mountain Power Corporation recently found itself at the center of controversy over its claims regarding renewable energy. The utility owns and is involved with a variety of renewable energy generation projects in Vermont, including wind and solar projects. It sells energy produced from these projects to Vermont customers, while simultaneously selling some of the RECs generated by these sources to out of state utilities.
In 2014, concerns over "double counting" of renewable energy attributes led Connecticut to ban the use of RECs from renewable generation that also is counted toward another state’s renewable goals for meeting Connecticut's requirements, and REC marketer NextEra Energy to notify New England market participants that it would no longer buy Vermont RECs.
On September 15, 2014, a group of petitioners asked the Federal Trade Commission to investigate Vermont utility Green Mountain Power Corporation's claims that it is providing its customers with electricity from renewable sources such as commercial wind and solar projects, given its separate sale of the RECs to out of state utilities. The Federal Trade Commission regulates claims about the environmental impacts of commerce under Section 5 of the Federal Trade Commission Act, including claims regarding the production, sale, and use of renewable energy. In their complaint, the petitioners claimed that "Vermont customers are being misled into thinking that they are buying 'renewable energy,' when in fact what they are getting is 'null' electricity consisting of a mix of fossil fuel, nuclear, gas and other 'brown' sources of electricity from the regional grid."
The FTC responded to this petition in February 2015 by issuing a letter to Green Mountain Power's counsel expressing concern that the utility might have created confusion for its customers about the renewable attributes of the power they purchased by not “clearly and consistently communicating” that it sells RECs for most of its renewable energy-generating facilities to entities outside Vermont. In the letter, the FTC said that it had not found that any Green Mountain Power statements violated the Federal Trade Commission Act. However, the Commission urged Green Mountain Power in the future to prevent any confusion by clearly communicating the implications of its REC sales for Vermont customers and REC purchasers.
The FTC letter represents the latest salvo in efforts to regulate claims regarding the production, sale, and use of renewable energy. To help marketers avoid making deceptive environmental claims, for over 20 years the FTC has issued "Green Guides" providing its administrative interpretation of the law. The Green Guides outline general principles that apply to all environmental marketing claims and provide guidance regarding many specific environmental benefit claims, including renewable energy claims. The Green Guides, as well as the recent FTC letter, illustrate the importance of caution in making claims about renewable energy in business activities.
North Carolina offshore wind environmental assessment
Tuesday, February 17, 2015
The U.S. Department of the Interior's Bureau of Ocean Energy Management has released an environmental assessment of the impacts of leasing sites off the North Carolina coast for offshore wind projects. This milestone supports the Obama administration's plan to offer site leases on the outer continental shelf for renewable energy projects.
Since 2012, BOEM has solicited public comment on the prospect of leasing about 307,590 acres off North Carolina for potential offshore wind development. BOEM has identified three Wind Energy Areas offshore North Carolina:
On January 22, 2015, BOEM announced the availability of an environmental assessment for public review and comment. Under the National Environmental Policy Act or NEPA, an environmental assessment or EA considers the potential impacts of proposed federal action and analyzes
reasonable alternatives to the proposed
action. In this case, the action proposed is BOEM's issuance of commercial wind leases and allowing of site characterization and assessment activities on
the Atlantic Outer Continental Shelf
offshore North Carolina.
BOEM's environmental assessment for North Carolina offshore wind leasing provides the framework for potential federal lease auctions for North Carolina offshore wind sites. The environmental assessment is available for public comment through February 23, 2015.
Since 2012, BOEM has solicited public comment on the prospect of leasing about 307,590 acres off North Carolina for potential offshore wind development. BOEM has identified three Wind Energy Areas offshore North Carolina:
- the Kitty Hawk Wind Energy Area (about 122,405 acres), beginning about 24 nautical miles (nm) from shore and extends approximately 25.7 nm in a general southeast direction;
- the Wilmington West Wind Energy Area (about 51,595 acres), beginning about 10 nm from shore and extends approximately 12.3 nm in an east-west direction at its widest point; and
- the Wilmington East Wind Energy Area (about 133,590 acres), beginning about 15 nm from Bald Head Island at its closest point and extends approximately 18 nm in the southeast direction at its widest point.
 |
| BOEM's map of North Carolina Wind Energy Areas. |
BOEM's environmental assessment for North Carolina offshore wind leasing provides the framework for potential federal lease auctions for North Carolina offshore wind sites. The environmental assessment is available for public comment through February 23, 2015.
Apple makes California solar deal
Thursday, February 12, 2015
Electronics manufacturer Apple has announced an
$848 million deal to buy electricity from a solar energy project to be developed in California. Project developer First Solar has described the power purchase agreement as "the largest agreement in
the industry to provide clean energy to a commercial end user."
Earlier this week, Apple announced the deal with First Solar, Inc., to buy power from First Solar's California Flats Solar Project in Monterey County, California. Under a 25-year power purchase agreement or PPA, Apple will buy the equivalent of 130 megawatts of the solar project's output.
First Solar is a vertically-integrated solar company, manufacturing solar photovoltaic panels, developing utility-scale photovoltaic power plants, and providing solar project support services. First Solar boasts involvement with over 10 gigawatts of installed solar photovoltaic capacity worldwide. Its resume includes the 550-megawatt Topaz Solar project in California and the 290-megawatt Agua Caliente project, which was once the world's largest operating solar energy project.
First Solar's California Flats Solar Project will occupy a 2,900-acre site on the Jack Ranch in Cholame, California. Owned by Hearst Corporation, the project site was formerly a dryland farm, and occupies about 3% of the Jack Ranch property. First Solar expects to begin construction later this year, and to complete the project by the end of 2016.
With a total project capacity of 280 megawatts, Apple's 130-megawatt commitment covers about 46% of the project's output. The project's remaining 150 megawatts will be sold to utility Pacific Gas & Electric under a separate long-term PPA.
Apple has developed other renewable energy projects, including fuel cells and solar panels at its Maiden, North Carolina data center. Other high-tech companies have also made significant investments in renewable energy, including Google's commitment of over $1.5 billion to solar and wind projects through power purchase agreements and direct investments.
 |
| Solar photovoltaic panels in the Utah desert. |
Earlier this week, Apple announced the deal with First Solar, Inc., to buy power from First Solar's California Flats Solar Project in Monterey County, California. Under a 25-year power purchase agreement or PPA, Apple will buy the equivalent of 130 megawatts of the solar project's output.
First Solar is a vertically-integrated solar company, manufacturing solar photovoltaic panels, developing utility-scale photovoltaic power plants, and providing solar project support services. First Solar boasts involvement with over 10 gigawatts of installed solar photovoltaic capacity worldwide. Its resume includes the 550-megawatt Topaz Solar project in California and the 290-megawatt Agua Caliente project, which was once the world's largest operating solar energy project.
First Solar's California Flats Solar Project will occupy a 2,900-acre site on the Jack Ranch in Cholame, California. Owned by Hearst Corporation, the project site was formerly a dryland farm, and occupies about 3% of the Jack Ranch property. First Solar expects to begin construction later this year, and to complete the project by the end of 2016.
With a total project capacity of 280 megawatts, Apple's 130-megawatt commitment covers about 46% of the project's output. The project's remaining 150 megawatts will be sold to utility Pacific Gas & Electric under a separate long-term PPA.
Apple has developed other renewable energy projects, including fuel cells and solar panels at its Maiden, North Carolina data center. Other high-tech companies have also made significant investments in renewable energy, including Google's commitment of over $1.5 billion to solar and wind projects through power purchase agreements and direct investments.
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