Yesterday, the Minnesota Public Utilities Commission (“MPUC”) approved Xcel Energy’s first Minnesota-based Community Solar Garden (CSG) program. After Xcel’s initial program filing was rejected by the MPUC in April, Xcel filed a revised CSG tariff with the MPUC in June. In a related filing, Xcel also argued that a value of solar (“VOS”) rate for CSG projects was not in the public interest and applicable retail rates should be used for the program instead. The MPUC approved Xcel’s basic program, with relatively minor modifications and at the applicable retail rates. As a result, Xcel customers will soon be able to invest in a solar project without having to own a home or the perfect roof for solar.
Many of the details were already prescribed by statute (Minn. Stat.§ 216B.1641):
- Subscribers to a CSG will purchase one or more 200-watt subscriptions up to 120 percent of their energy load
- CSG projects must include at least 5 subscribers with no single subscriber amounting to more than 40% of the total CSG capacity
- Each CSG is to be no more than 1MW in size, but the program as a whole remains uncapped
The statute also requires that Xcel Energy purchase all of the energy output of a CSG system at a VOS rate once it is approved by the MPUC. Many interested parties have invested considerable time and resources into developing a way to calculate the costs and benefits distributed solar deliver to a utility, its customers and society (more on that process here, here and here). Last spring, the MPUC approved a final methodology to calculate VOS rates - the culmination of that work. Xcel’s CSG tariff filing was then the first test of the methodology and the CSG program its intended first application.
Ultimately, the MPUC approved the use of the applicable retail rates instead of a VOS rate as Xcel requested. With parties diverging on the VOS rate itself as well as what, if any, additional incentive may be needed to make the projects financeable, the MPUC opted to spend more time getting any future VOS rate and associated incentive right. As that work continues, the program will go forward with the rate for immediate CSG projects being the applicable retail rate and an additional 2-3 cent adder for associated solar renewable energy certificates transferred to the utility. This amounts to rates from approximately 11.5¢/kWh for larger systems subscribed by commercial and industrial customers to 15¢/kWh for smaller systems subscribed by residential customers.
Will such rates “reasonably allow for the creation, financing, and accessibility” of CSG projects under Minnesota law? One of these days, perhaps before the Harvest Moon, we will see whether Minnesota solar gardens are ready to sprout.
During today's open meeting, the Federal Energy Regulatory Commission (FERC) issued a proposed rulemaking that impacts the owners of gen-tie lines, particularly those owners who are developing multi-phase projects that require priority to interconnection capacity to support future phases. The proposed rule would ease existing FERC policies that treated gen-tie lines just like any other transmission facility and required owners to make interconnection capacity available to third parties if the owner could not provide enough documentation proving its planned use of the gen-tie lines.
FERC has proposed the following:
- Gen-tie line owners will be granted a blanket waiver from the requirement to (x) maintain a transmission tariff and OASIS and (y) comply with the standards of conduct. FERC will revoke that blanket waiver only when it is in the public interest to do so, and not simply when a third party requests transmission service over a gen-tie line.
- Third parties seeking to interconnect with existing gen-tie lines will be required to do so using the rules and regulations applicable to service requests under sections 210 and 211 of the Federal Power Act.
- Gen-tie owners who are eligible for the blanket waiver from maintaining a tariff, etc., will be granted a 5-year safe harbor period giving the owner the benefit of a rebuttable presumption that (1) the owner has plans to use the gen-tie line's capacity, and (2) the owner should not be required to expand its facilities. Third parties would have an opportunity to rebut that presumption, but those third parties would have the burden of proof. FERC proposes that the 5-year period would begin on the gen-tie energization date. Gen-tie owners would also be required to make an informational filing with FERC in order to take advantage of the safe harbor rights.
- Lastly, FERC has asked whether the affiliates of public utility transmission provider should receive the benefit of the proposed rules.
The proposed rulemaking is available here: Gen-Tie Rulemaking
Comments are due by 60 days after publication of the proposed rule in the Federal Register. Please let us know if you have questions about the proposed rulemaking and/or would like to submit comments to FERC.
The East Kern Wind Resource Area (EKWRA)--it's a mouthful--and it's also a hotbed for renewable energy development and the location of a fight over millions of dollars among Southern California Edison (SCE), the California ISO, and independent power developers (IPPs). Late last week, the Federal Energy Regulatory Commission (FERC) scored that fight in favor of SCE and the California ISO.
For the past few years, SCE has been working to reconfigure the transmission system in the EKWRA region in order to address a reliability issue occurring there. But the reconfiguration would have another impact--it would modify the transmission system in the area so that it became a distribution system under SCE, rather than CAISO, control. To IPPs, that modification came with significant cost consequences: in the interconnection process, IPPs funding network upgrades on the transmission system receive a full reimbursement for the cost of those upgrades; distribution upgrades, on the other hand, result in no reimbursement. For IPPs who had assumed they would be reimbursed the network upgrade costs that appeared in their interconnection agreements (which often cost a single project millions of dollars), it came as something of a surprise when they learned that the reconfiguration might cause their reimbursements to dry up.
And so the IPPs challenged SCE and the California ISO. In its decision, FERC determined that the reconfigured EKWRA facilities are distribution, or non-integrated facilities, and that the California ISO correctly transferred control over the facilities to SCE's tariff. As a result, no further reimbursements to the IPPs will occur. "Despite being informed of the possibility of reclassification, [the IPPs] made a business decision to proceed with interconnection." For some IPPs, this could have a very costly impact.
You can read the entire order here: EKWRA Order.
In a proposed decision issued yesterday from the California Public Utilities Commission, an administrative law judge (ALJ) determined that energy storage devices (i) that are paired with net energy metering- (NEM) eligible generation facilities, and (ii) that meet the Renewables Portfolio Standard Eligibility Guidebook requirements to be considered an "addition or enhancement" to NEM-eligible systems are "exempt from interconnection application fees, supplemental review fees, costs for distribution upgrades, and standby charges when interconnecting under current NEM tariffs.
The issue of whether solar PV-integrated energy storage could interconnect through NEM tariffs heated up in recent months as utilities in California determined that such systems were not NEM-eligible and therefore imposed additional requirements (and costs) in order for a paired solar PV system itself to be NEM-eligible. These requirements and costs acted as a barrier to using energy storage technologies with distributed generation. But in this proposed decision, the ALJ encouraged the state's utilities to take a "more proactive and collaborative approach to avoid creating barriers," and found that energy storage should be exempt from these additional requirements when certain conditions are met.
Sizing. The proposed decision states that NEM-paired storage systems with storage devices sized at 10 kW or smaller are not required to be sized to a customer's demand or the NEM generator. For NEM-paired storage systems with storage larger than 10 kW, (x) the discharge capacity of the storage system may not exceed the NEM generator's maximum capacity, and (y) the maximum energy discharged by the storage device shall not exceed 12.5 hours of storage per kW.
Metering. With respect to metering requirements, the proposed decision again draws distinctions between storage systems above 10 kW discharge and those at 10 kW and below discharge capability, although the decision proposes to impose certain requirements on both categories in order to "preserve the integrity of NEM." For systems at 10 kW and below, the decision proposes using a de-rate factor to measure the AC energy that flows into, and out of, the NEM generator. NEM-paired systems larger than 10 kW will be required to adhere to metering requirements similar to those under the NEM Multiple Tariff Facilities provision of utilities' NEM tariffs, although the costs of metering will be capped at $500. In either category, the proposed requirements aim to ensure that only NEM-eligible generation receives NEM credit.
The full proposed decision may be viewed here: CPUC Proposed Decision re Energy Storage
Ameren Should LOSE the Latest Battle Over Option 1 Network Upgrade Funding in the Midcontinent ISO Region
Ameren is at it yet again--perpetuating a method for funding generator interconnection network upgrades in MISO that the Federal Energy Regulatory Commission (FERC) found to be unjust, unreasonable, and discriminatory over three years ago. Ameren has already won two cases that allowed it to continue using Option 1 funding for certain interconnection customers. But Ameren should lose this one. Here's why:
A Brief History. Prior to March 22, 2011, the MISO tariff provided three methods for funding interconnection network upgrades. Option 1 required an interconnection customer to upfront fund the cost of network upgrades (post security and pay monthly construction costs); when those upgrades became commercially operational, the transmission owner would reimburse the full amount paid by the customer and then establish a transmission rate to charge the customer for using the upgrade on an ongoing basis. Option 2 funding also required the customer to pay upfront construction costs, but then the customer was reimbursed a portion of those costs following commercial operation. Option 2 did not include an ongoing rate. As a result, over time Option 1 funding could result in multiples of the actual cost that a customer might pay under Option 2. (The third option--"self-fund"--allowed a transmission owner to pay upfront costs itself and then charge a usage rate.)
On March 22, 2011, FERC responded to a complaint about Option 1 funding by independent power producers, determining that the method was "unjust, unreasonable, and discriminatory." FERC ordered MISO to remove Option 1 funding from its tariff. That order is found here: E.ON Climate & Renewables.
However, in the past couple of years, Ameren has successfully won the right to continue using Option 1 funding in interconnection agreements that were signed prior to FERC's decision in E.ON. After FERC issued its decision in E.ON, certain customers attempted to obtain the benefit of that decision by having FERC alter their agreements where they had agreed to Option 1 funding. But FERC denied the attempts, primarily on the basis that those prior agreements expressly provided for Option 1 funding and that it would not be in the public interest to unilaterally modify the contracts. In other words, those customers who sought to benefit from the E.ON decision had express notice that Option 1 funding would apply and they failed to raise a timely dispute; FERC would not reset the contracts they had agreed to. Those decisions are available here: Rail Splitter (agreed to Option 1 funding by signing a Facilities Service Agreement) and Hoopeston (agreed to Option 1 funding in its interconnection agreement).
Now we come to the current dispute over Option 1 funding. This docket focuses on an interconnection agreement that Ameren signed with White Oak Energy in 2007. At that time, Option 1 funding existed under the MISO tariff, but White Oak's interconnection agreement said nothing expressly about Option 1 funding. In addition, Ameren was not required to select the funding method until the network upgrades reached commercial operation. At the time of signing its interconnection agreement, if White Oak had disputed the potential application of Option 1, FERC would have likely dismissed the dispute for being unripe. It wasn't a real issue yet.
Fast forward four years. Ameren completed construction of White Oak's network upgrades in 2011 and notified White Oak at that time that Option 1 would apply. White Oak disagreed repeatedly, leaving Ameren forced to file White Oak's Facilities Service Agreement unexecuted with FERC. Under the proposed funding method, White Oak's network upgrades (actual cost $2,399,128) will cost $8,292,180 over 20 years under the ongoing rate. You can see Ameren's application to FERC here: White Oak FSA Application.
So why should White Oak receive a different result than the customers in Rail Splitter and Hoopeston? White Oak should be treated differently because, until now, it had no prior opportunity to complain to FERC about this method for funding network upgrades that we know to be discriminatory. Unlike the customers in Rail Splitter and Hoopeston, who waived their opportunity to complain and consequently needed FERC to undo contracts they'd agreed to, White Oak has never agreed to Option 1 funding--there is no contract to undo As a result, White Oak should now be afforded the chance to argue against Option 1 funding on the merits (see E.ON), rather than being hung up by procedural technicalities and the Mobile-Sierra doctrine.
If FERC were to rule in White Oak's favor, then the decision would help to restrict the application of this discriminatory method of funding network upgrades to a limited group of interconnection customers (i.e., those who expressly agreed to Option 1 in a contract) and to insulate those who are just now receiving notice of Option 1 funding from the absurd results that accompany it. But we'll need to wait and see if those at FERC who call balls and strikes see it the same way.
On Thursday, March 27, 2014, the California Public Utilities Commission established rules for transitioning distributed generation renewable energy systems from the current net energy metering (NEM) arrangement to the successor tariff which will be adopted by the CPUC in 2015.
The decision, D.14-03-041, was mandated by last year’s passage of AB 327, requiring implementation of changes to California’s NEM program by 2017. AB 327 specifically directed the CPUC to establish a transition period for “pre-existing” systems based on a “reasonable expected payback period” and other factors consistent with California’s policy to promote the use of renewable energy. Under the legislation, systems installed prior to the earlier of July 1, 2017, or the date upon which the customer’s utility reaches the 5% cap on its capacity subject to the net metering tariff, would be eligible for the transition period.
The CPUC decided that 20 years from the date of installation (interconnection) would be the transition period for pre-existing systems. The adopted period is longer than advocated by the utilities and certain ratepayer organizations and shorter than urged by some members of the solar industry and local governments. The Commission also rejected arguments that customers installing systems after adoption of the transition rule should have shorter transition periods on the theory that they had notice of the coming change in tariffs and therefore could not have had reasonable expectations of more lengthy “payback” periods.
Along with setting the length of the transition period, the Commission decided that a system would not lose its qualification for the 20 year transition period by a modification increasing capacity less than 1kw or 10%, nor by its transfer to new ownership at the same location. More substantial increases in capacity or transfer of a system to a new location would terminate the transition period for the affected system.
In future rulemakings, the CPUC will address what will replace the existing NEM tariff, as well as the circumstances under which storage systems will qualify for NEM arrangements.
This post was authored by my colleague, Howard Susman. For more information, contact Howard at (858) 794-4111.
Fake Punt! Minnesota Commission Immediately Reevaluates Motion, Advances Solar Plus One (or more) Gas Plants
In a follow up to our prior post, we now report that the Minnesota Commission subsequently modified its initial decision to clarify that Xcel Energy is directed to negotiate a power purchase agreement with the solar bidder, which will be reviewed by the Commission to ensure the terms are consistent with the public interest. Xcel is also directed to negotiate with the natural gas project bidders and develop pricing terms for its own natural gas project. Here is the text from the revised motion.
Although all terms will be reviewed by the Commission, Xcel Energy's Minnesota ratepayers will likely have a utility-scale solar project and at least one natural gas project to meet capacity needs in the 2017-2019 timeframe. And it's fair to state the Commission's decision puts solar in the red-zone, first and goal.
After the years of inconclusive resource planning, months of contested case proceedings, and days of oral argument, discussion and review that led to today’s deliberations, the Minnesota Public Utilities Commission (“Commission”) unanimously decided not to decide. The ultimate question before the Commission was what capacity needs had been determined in the record and what should be done to fill that need on Xcel Energy’s system. At the turn of the new year, the Administrative Law Judge’s (“ALJ”) answers to these questions made national news by finding that the solar bid provided the best value for ratepayers (see our blog on that here). The ALJ made his determination, in part, based on new modeling done at the request of the Commission given the significant changes in circumstances that had occurred since docket was opened (e.g., Xcel Energy acquired 750MW of new wind and Minnesota passed a Solar Energy Standard). In light of the changed circumstances and uncertain need, the ALJ recommended selection of the solar resource that was independently “needed” by statute, a capacity bid that could be added as necessary to bridge for any further shortfall, and then conduct a more thorough analysis for the longer-term needs. Today the Commission instead chose to rely primarily on the original need determination that opened the docket, accept the ALJ’s findings only to the extent they were consistent with their own findings, and direct Xcel to negotiate with everyone proposing to build something and report back.
Despite the above, the decision is a significant step forward for solar. This was the first time a solar proposal had competed directly with natural gas in a resource acquisition process and, despite significant pressure from the Department of Commerce to shuffle the solar bid off into a separate, solar-only proceeding, the Commission confirmed today that the solar bid was welcome at the big kids table.
Look for a forthcoming Order that includes something like this:
In order to meet reliability and adequacy requirements and to comply with MN energy policy statutes, direct Xcel to separately negotiate power purchase agreements with Geronimo Energy, Calpine, Invenergy and develop pricing terms for Black Dog 6 to address the overall Xcel system needs identified in this record and the March 5, 2013 Integrated Resource Plan Order and determine which resources best meet system needs and are in ratepayers’ best interests.
Find that negotiated terms that shift risk or unknown costs to ratepayers are not likely to be reasonable. Find that bidders shall be held to the prices and terms used to evaluate each bid for purposes of cost recovery from Xcel ratepayers. Ratepayers will not be at risk for costs that are higher than bid or for benefits assumed in bids that do not materialize. If actual costs are lower than bid, the bidders should be allowed to keep those savings.
Require that power purchase agreement provide terms that sufficiently protect ratepayers from risks associated with the non-deliverability of accredited capacity or energy from the projects as proposed.
"Don't mess with Texas." Apparently the slogan even applies to liquidated damages clauses.
This morning, the Supreme Court of Texas issued a decision in a drawn-out fight between wind developer FPL Energy and the power marketer TXU Portfolio Management. The dispute originates from power purchase agreements (PPAs) in which FPL failed to deliver enough electricity and renewable energy credits (RECs) to cover its performance guaranty over a period of four years, in large part because of congestion and resulting curtailment orders by ERCOT. TXU initially brought suit for the shortfall, and FPL countered by claiming that the shortfalls were due to curtailments by ERCOT, and that TXU caused those curtailments to occur by failing to ensure that transmission capacity would be available away from the project delivery point. In any event, FPL argued that the liquidated damages for the shortfall amounted to an unenforceable penalty.
At the time of negotiating the PPAs, TXU and FPL agreed by contract that a shortfall in RECs would trigger liquidated damages in the amount of $50 per REC. There was no market for RECs at the time, and so the parties had settled on this damages amount by using the $50 per REC penalty that the Public Utility Commission of Texas could impose on utilities for not acquiring enough RECs. (The parties also agreed to an alternative price of twice the market value of RECs as determined by the Public Utilities Commission of Texas, if any such determination occurred.)
But today the Supreme Court of Texas ruled that the parties' agreed-upon liquidated damages provision amounts to an unenforceable penalty. Although the clause may have been a reasonable estimate of TXU's damages at the time of negotiation--particularly given that the clause mirrored the regulatory penalty for REC shortfalls--the provision failed to reflect actual damages at the time it was applied. The parties' powers of divination had failed them!
In the court's words: "When the liquidated damages provisions operate with no rational relationship to actual damages, thus rendering the provisions unreasonable in light of actual damages, they are unenforceable." In other words, it does not matter that the liquidated provision in the PPA was a reasonable estimate of damages at the time it was negotiated. Instead, what matters is whether the liquidated damages provision at the time it is applied reflects actual damages. As a result, a provision that was once reasonable became invalidated when market values later created a significant difference between the past estimate and actual damages.
To put this in a broader context, not all states approach a liquidated damages provision in this way. In its decision, the Supreme Court of Texas applied the "second-look" doctrine to the liquidated damages clause (despite seemingly starting toward a different doctrine), meaning that the court considered whether the liquidated damages provision was reasonable at the time it was negotiated, and also whether it is reasonable at the time it is applied. A "one-look" state considers only whether a liquidated damages clause was reasonable at the time it was negotiated. If FPL and TXU had chosen in the PPA to apply the laws of a "one-look" state, then the result may have had many differences--tens of millions of differences.
As to how FPL wound up in the shortfall position to begin with, FPL argued that TXU had failed in its contractual duty to provide transmission capacity to deliver electricity away from the delivery point. That failure resulted in higher than expected congestion and resulting curtailment orders from ERCOT. TXU countered that its transmission service obligations were limited to transmission for “Net Energy” - i.e. energy that was first delivered to the Delivery Point. The court agreed with TXU, holding that TXU’s transmission obligations arose only when the FPL-generated electricity actually reached the Delivery Point. The court reached this holding notwithstanding its recognition of FPL’s argument that transmission congestion and ERCOT's related curtailment orders had prevented electricity from reaching the delivery point in the first place.
You may read the court's opinion here: TXU v. FPL.
Yesterday afternoon, the Minnesota Public Utilities Commission approved the methodology for calculating value of solar (VOS) tariffs in Minnesota as developed by the Department of Commerce. In doing so, Minnesota became the first in the nation to adopt a VOS tariff methodology.
The Commission was required by statute to take action on the VOS calculation methodology by the end of the month. It had three options: to approve it as proposed, reject it, or approve it with modifications and with the consent of the Department. For background on the Department's January 31st recommendation, see our blog posts here and here. The Department subsequently included several modifications affecting the fuel price escalation factor, the avoided distribution capacity cost, and the environmental cost categories.
In its ruling, the Commission approved the Department’s methodology, as amended, by a 3-2 vote.
The motion to approve carried after extensive discussion on the appropriate cost or placeholder value for the avoided carbon dioxide emissions associated with solar generation. The Department selected a federal social cost of carbon value because it felt this calculation more appropriately captured the marginal damage value of incremental additional units of energy. Others had argued a different value should be used, including an existing externality value set in the state two decades ago or a more recent planning value. Further complicating the discussion was the fact that Minnesota is separately about to review these externality values in a separate docket.
Ultimately the Department's use of a federal social cost of carbon value was adopted, but the Commission also separately voted to clarify that the Commission's adoption of the Department's methodology values was not intended to have any precedential effect.
The Commission declined to incorporate various additional value components including a separate value for the transferred renewable energy certificate or for solar energy standard compliance that would be over and above the environmental benefit value already included in the Department's methodology. In addition several issues were raised and discussed that the Commission ultimately determined were outside the scope of this decision but worth further consideration. In order to follow up on these issues the Commission directed staff to solicit comments on the effect of the decision on existing net metered-customers, conformity with PURPA, REC ownership disclosure and other issues. In certain cases, it also determined the Commission would have another chance to more directly consider the issues when a specific utility tariff that applies the methodology is before the Commission for approval.
The next step in the process is for utilities to determine whether to elect to create an alternative tariff based on the methodology for customer projects 1MW and under and then file the proposed tariff with the Commission. Xcel Energy will file a VOS tariff, at a minimum, for the utility's developing Community Solar Garden Program (CSG). Within 30 days of the Commission's Order approving the VOS methodology, Xcel must file a VOS tariff for the purposes of its CSG program, or file a VOS calculation for the CSG program and show cause why the rate should not be implemented.
After a full day of hearing arguments on Xcel’s proposed Community Solar Garden (CSG) program (see more on that here), the Minnesota Public Utilities Commission deliberated in public on the issue yesterday and made some important modifications to Xcel’s proposal. The program would allow Xcel customers to invest in off-site solar facilities and receive bill credit for their portion of generation. Ultimately that credit would be at the Value of Solar rate, but as parties await a decision on the Value of Solar (VOS) methodology (more on the VOS here), the Commission settled on an interim rate for the program (though its final vote on the matter is still forthcoming). It is largely based on average retail rates but importantly includes a placeholder value of any transferred Solar Renewable Energy Certificates (SRECs). A CSG developer could transfer the S-RECs to Xcel at a compensation rate of $.02/kWh for facilities with a capacity greater than 250 kW and at $.03/kWh for those with a capacity of 250 kW or less. The S-REC value is not intended to reflect a market rate and is intended and is intended to be strictly temporary, expiring upon the approval of Xcel’s VOS tariff. Furthermore the rate and S-REC value are to be reviewed annually and adjusted if necessary.
The illustrative range of rates (assuming the SREC is transferred) is as follows:
Residential: $.14033 or $.15033
Small General: $.13738 or $.143738
General Service: $.11456 or $.12456
In addition, Xcel’s proposed 2.5 MW quarterly cap on the program was removed given the statute precludes a cap. While a final decision has not yet been issued by the Commission, newsmedia have already begun to report on it (see Star Tribune article here).
Converting a qualifying facility's legacy PURPA interconnection agreement to a FERC-jurisdictional agreement can be an effective way to bypass the numbing headache that often accompanies taking a new power generation project through the interconnection queue. One may even be able to throw in a repower and, voila!, you have a refreshed facility that can operate for decades more in broader bilateral power markets without having years of interconnection delay.
But there are ins-and-outs to these conversions, and today FERC addressed the question of whether a qualifying facility owner may necessarily convert the capacity that's stated in its PURPA interconnection agreement. For qualifying facility owners--it isn't the answer you wanted.
See FERC's order by following this link: CalWind Order.
In May 2013, the Minnesota Legislature passed legislation that, among other things, set a solar standard, directed Xcel Energy to develop a community solar garden program, and provided for the development of an alternative tariff mechanism to net metering that would also serve as the rate for community solar garden programs. Under this new scenario and instead of traditional net-metering arrangements, customers would potentially buy all of their electricity from their local distribution utility and then sell all of their PV generation under that utility's Value of Solar (VOS) tariff which would be designed to capture the societal value of PV-generated electricity.
The legislation directed the Department of Commerce to work with stakeholders to develop a VOS methodology and to deliver its recommendations to the Minnesota Public Utilities Commission (Commission) on Friday, January 31, 2014. The Department’s filing today includes its recommendation, with a more in-depth document addressing the methodology. The Department’s recommendations do not set a rate, but rather propose the methodology for calculating a utility-specific rate for distributed PV solar (1 MW and smaller). If the Department’s sample calculation is any indicator of what’s to come, however, the value went from $0.126/kWh in its initial draft to $0.135/kWh in the documents filed this morning.
By statute Minn. Stat. § 216B.164, subd. 10, the VOS must take into account the following values for distributed solar PV:
- Energy and its delivery;
- Generation capacity;
- Transmission capacity;
- Transmission and distribution line losses; and
- Environmental value.
The legislation also provided for the Department to incorporate, based on known and measurable evidence of the cost or benefit of solar operation to the utility, other values into the methodology including, for example, credit for systems installed at high-value locations on the distribution grid. The Department began convening stakeholders and receiving comments from interested parties last fall in preparation for meeting the January 31 deadline. Information on those proceedings can be found here and was used to form the ultimate recommendations delivered to the Commission.
The valuatation categories the Department included in its proposed methodology include the following, with the first three largely falling under the first statutory requirement above:
- Avoided fuel cost
- Avoided plant O&M - Fixed
- Avoided plant O&M - Variable
- Avoided Gen Capacity Cost
- Avoided Reserve Capacity Cost
- Avoided Trans. Capacity Cost
- Avoided Environmental Cost
- Avoided Voltage Control Cost
- Solar Integration Cost
The slight upward changes between the example calculation in the Department’s November draft and that filed today were largely in the avoided environmental cost and the avoided distribution capacity cost categories. The methodology then calls for a conversion of the 25-year levelized value to an equivalent inflation adjusted credit rate. The methodology, if approved by the Commission, would then be available for utilities to choose to use in lieu of net metering. As such the rate itself will become utility-specific and would be recalculated by any given utility on an annual basis. While it will generally be optional for utilities to elect to apply a VOS tariff in lieu of net-metering, Xcel Energy must apply the VOS tariff to its developing Community Solar Garden program (more on that evolving program is in Commission Docket No. M-13-867 and Xcel’s initial proposal can be found here.
The Commission issued notice of an expedited comment period with initial comments due February 13, 2014 and reply comments due February 20, 2014. The expected meeting date is March 12, 2014. By statute, the Commission must approve, modify, or disapprove the methodology within 60 days of its submission (early April).
Like other Independent System Operators have done before it, the Southwest Power Pool (SPP) is back at the drawing board in an effort to further refine its generator interconnection procedures and improve on queue reforms initially put in place in 2009. And also like other ISOs that have continued to tinker with queue reform, SPP is looking to make the interconnection process more demanding so that only the "viable" projects get through.
Among the various proposed changes, there are a few that generation developers should key in on.
- SPP proposes to allow later-queued customers pass by higher-queued customers in terms of queue priority, provided that the later-queued customer is the first to reach the Facilities Study phase. Previously, customers who reached the DISIS queue could not lose their queue priority and be passed by. But now priority goes to customers who reach the Facilities Study first. This change, of course, will impact customers' cost responsibilities, as priority to unused transmission capacity will be subject to the race to the top.
- To enter the Facilities Study phase (and lock in queue priority), customers must complete a financial milestone by providing security equal to $3,000 per megawatt of the generator size. SPP has proposed removing other choices that customers previously used for entering this phase of the study process. But watch out--customers who later withdraw from the queue may forfeit this deposit.
- Prior to signing an interconnection agreement, an interconnection customer may extend its commercial operation date by no more than three years. Anything longer will be considered a material modification and will result in a loss of queue position.
- Under proposed revisions to the interconnection agreement, a customer would have three years following its designated Commercial Operation Date to complete its generating facility. A customer who fails to do so will have its interconnection agreement terminated. In addition, customers who fail to bring their full generation capacity online within that timeframe will lose rights to any capacity that remains unused at the three-year mark.
- Lastly, customers who sign an interconnection agreement must post 20% of the costs of their network upgrades within 30 days of execution. This deposit may be non-refundable under certain circumstances.
Given the queue reforms that FERC has accepted in other regions, it's likely that much of what SPP has proposed will make it into the tariff.
SPP has asked that these latest reforms be made effective March 1, 2014, and applicable to any customer who does not have an interconnection agreement with an earlier effective date. For those customers currently negotiating an interconnection agreement: the race is on.
Thousands of solar industry participants gathered in Chicago for the Solar Power International expo in Chicago, Illinois on October 21-24 to discuss the state of the solar industry. Participatnts included banks, investors, developers and equipment suppliers, and also several Stoel Rives attorneys.
Many themes emerged during the week-long event, and a common thread running through these themes was “change.” The solar industry is undergoing significant changes, as demonstrated by the following:
- Stoel Rives announced that Federal Energy Regulatory Commission Chairman Jon Wellinghoff will join the firm later this year following his impending resignation from the Commission;
- The regulatory environment continues to morph as the 1603 cash grant phases out while the ITC reemerges pending its expiration, net-metering battles rage on in multiple states, and California has required investor owner utilities to procure and invest in significant amounts of energy storage;
- Companies continue to search for investment grade projects while developers continue to hunt for PPAs with sustainable pricing;
- Chinese equipment manufacturers continue to factor in the space, and several companies from mainland China attended the expo for the first time, now also joined by a growing number of Taiwanese and Korean companies;
- As utility scale development opportunities in the United States continue to stagnate, many companies are turning their focus to Latin America where new and potentially lucrative opportunities are emerging;
- The industry seems ripe for consolidation and the remainder of 2013 and 2014 may witness several significant mergers.
In this time of significant change, Stoel Rives will continue to serve the solar industry by providing high quality legal services and innovative solutions for the issues of today and the issues of the future.
After much anticipation, Xcel Energy submitted its petition for approval (PDF) of the company's proposed community solar gardens program on September 30th. The program would give utility customers a new way to engage in solar generation without having to invest onsite. A solar garden is a "facility that generates electricity by means of a ground-mounted or roof-mounted solar photovoltaic device whereby subscribers receive a bill credit for the electricity generated in proportion to the size of their subscription." Other required details of the program are set forth in Minnesota Statutes 216B.1641 and include:
- each garden must also have at least 5 subscribers whereby no single subscriber has more than a 40 percent interest;
- each subscription must be at least 200 watts and the total garden size cannot exceed 1 MW; and
- each garden must be within Xcel's service territory and its subscribers must be retail customers located in the same or contiguous county as the solar garden site.
While many of the details of the program are set forth by law, Xcel also clarified several procedural elements of its filing. For example, Xcel plans to take applications online on a first-come, first-served basis but limit the program to 2.5 MW per quarterly application period for the first two years of the program. A successful applicant would enter into a 20-year, fixed rate power purchase agreement with Xcel Energy.
Although the rate paid for the energy generated by a solar garden facility will eventually be the forthcoming Value of Solar rate, Xcel states that it is likely the solar gardens program will need to begin operations and issue bill credits before Xcel has a Value of Solar rate in place. For the interim period Xcel proposed to use a blended retail rate that differs by demand and non-demand class and by season. For no-demand metered service this would be just over $0.10/kWh and for demand metered service this would be just over $0.06/kWh, both with slight increases for the summer months. This price is expected to include the transfer of any and all solar renewable energy certificates generated by the garden to Xcel.
Yesterday, Minnesota Governor Mark Dayton signed the Omnibus Energy Bill into law. After months of negotiations, state legislators came to an agreement that brings Minnesota to the forefront of solar power following the creation of a solar energy standard, community solar garden program, and a unique value of solar tariff. Key provisions of the new law include: a solar energy standard, performance-based incentives for solar photovoltaic module manufactured in Minnesota, new pricing options for public utilities, and an expanded opportunity for distributed generation.
Solar Energy Standard
With Governor Dayton’s signature, Minnesota became the 17th state to enact a solar energy standard. Minnesota’s solar energy standard requires investor owned utilities to generate or procure a sufficient amount of solar energy so that by the end of 2020, at least 1.5 percent of the utility’s total retail electricity sales to retail customers in Minnesota comes from solar energy, with the goal of reaching ten percent solar by 2030. In addition, at least ten percent of the 1.5 percent required by 2020 must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Notably, the 1.5 percent requirement is in addition to, rather than carved out of, Minnesota’s existing renewable energy standard. Initial reports estimate that the solar energy standard will result in the development of more than 450 megawatts of solar by 2020.
Made in Minnesota
In addition to creating a solar energy standard, the new law creates a performance-based incentive for systems that use solar photovoltaic modules that were certified as "Made in Minnesota." Beginning January 1, 2014, and every each January 1 through 2023, $15 million will be collected from the public utilities and distributed to owners of eligible grid-connected solar photovoltaic modules with a nameplate capacity below 40 kilowatts as a production incentive payment. The commissioner of commerce is responsible for setting the solar energy production incentive rate for each module within 90 days of certifying a module as Made in Minnesota.
Solar Energy Incentive Program
The new law creates an additional incentive for small solar energy systems. Set to begin in 2014 and operate for five consecutive years, the program will collect $5 million a year from Xcel Energy (through its renewable development account) to fund solar energy systems of no more than a total nameplate capacity of 20 kilowatts. This program will assist the utilities in complying with their duty to secure 10% of the 1.5% solar standard from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less.
Community Solar Gardens
By September 20, 2013, Xcel Energy must file a plan with the Public Utilities Commission ("PUC") to operate a community solar garden program, which will begin 90 days after the PUC approves the plan. Community solar gardens give utility customers and other members of the designated community the option to buy solar panels that will be included in an array built in a communal location, rather than on the purchaser’s roof or in their backyard. Participants receive the benefit of a monthly credit on their electric bill while avoiding the cost of maintaining the panels. A community solar garden may be owned by either a public utility or any other entity or organization that contracts to sell the output and must be designed to offset the energy use of at least five subscribers in each community, of which no single subscriber has more than a 40% interest. A single community solar garden cannot have a nameplate capacity of more than one megawatt or supply more than 120 percent of the average annual consumption of electricity by each subscriber at the premises to which the subscription is attributed.
The first community solar garden (developed before the passage of the new law) in Minnesota is expected to be completed this weekend and consists of 171 panels located on an empty field owned by the Wright-Hennepin Cooperative Electric Association. Subscribers purchased panels priced at $869 each.
Value of Solar Tariff
For the first time, a public utility will be able to offer an alternative tariff that compensates customer-generators through a credit on their energy bill for the value to the utility, its customers, and society for operating distributed solar photovoltaic resources interconnected to the utility system and operated by the customer-generator primarily for meeting his own energy needs. Once approved, the utility’s value of solar tariff can be applied to a customer-generator’s interconnections occurring after the date of approval and in lieu of the rates mentioned in the net metering section below.
By January 13, 2014, the Department of Commerce’s Division of Energy Resources ("DER") is tasked to establish a methodology that utilities would follow in appropriately calculating or setting their alternate tariffs. The calculations should, at a minimum, account for the value of energy and its delivery, generation capacity, transmission capacity, transmission and distribution line losses, and environmental value. The DER may also, based on known and measurable evidence of the cost or benefit of solar operation to the utility, incorporate other values into the methodology, including credit for locally manufactured or assembled energy systems, systems installed at high-value locations on the distribution grid, or other factors. Further, the PUC may not authorize a utility to charge an alternative tariff rate that is lower than the utility's applicable retail rate until three years after the PUC approves an alternative tariff for the utility. Lastly, the utility must enter into a contract with the owner of the solar photovoltaic device receiving an alternative tariff rate that has a term of at least 20 years and pays the same rate per kilowatt-hour generated each year for the term of the contract.
The new law will also greatly expand the opportunity for distributed generation by raising the limit on net metering from 40 kilowatts to 1,000 kilowatts. Facilities generating less than 40 kilowatts will continue to receive the utility’s retail rate for net excess generation, while systems between 40 kilowatts and 1,000 kilowatts will receive the avoided cost rate for net excess generation. In the future, utilities will have the opportunity to decide whether to continue offering net metering or switch to a value of solar tariff. Once the cumulative generation of net metered facilities reaches four percent of the public utility’s annual retail electricity sales, the public utility may request the PUC to limit the public utility’s additional net metering obligations.
In addition to raising the cap on net metering, the new law authorizes utilities to use meter aggregation. Meter aggregation allows customer-generators to offset charges for energy usage from multiple meters located on contiguous property owned by the customer.
Setting the Stage for Further Renewable Development
Although the final version of the new law did not increase the existing Minnesota renewable energy standard, it directs all electric utilities and transmission companies to conduct an engineering study of the impacts on reliability and costs of, and to study and develop plans for the transmission network enhancements necessary to support, increasing the renewable energy standard to 40% by 2030, and to higher proportions thereafter, while maintaining system reliability. A team of 15 individuals appointed by the commissioner, in consultation with the electric utilities and transmission companies, will review the study’s proposed methods and assumptions, ongoing work, and preliminary results. The study is due to be completed by November 1, 2014. Other studies required as part of the new legislation include: the value of on-site energy storage and the value of solar thermal.
Today the Minnesota Senate passed its omnibus energy bill by a vote of 37-26. This follows the Minnesota House of Representatives’ passage of its version of the bill on Tuesday. The bills now move to a conference committee for consolidation. After the conference committee completes its work, the consolidated bill will then return to each chamber for a final vote before heading to Governor Dayton’s desk.
Some major differences between the two bills means the conference committee has its work cut out for it. For instance, the Senate’s bill contains a 1% solar standard while the House of Representatives’ version includes a much more aggressive 4% solar standard. Whatever the number that ends up in the final bill, Minnesota is set to become only the 17th state to enact a solar standard, and one of the few whose standard is not a carve-out of an existing renewable energy standard.
On May 7th, the Minnesota House of Representatives passed its omnibus energy bill by a vote of 70-63. The bill includes a provision that requires investor-owned utilities to obtain 4 percent of their power from solar by 2025, with a goal of reaching 10 percent by 2030. In contrast to the aggressive House bill, the Minnesota Senate’s omnibus energy bill contains a more modest requirement for 1 percent by 2025. If signed into law, Minnesota would be the 17th state to enact a solar standard. Unlike solar standards in other states, however, this standard is not a carve-out of the existing 25 percent by 2025 renewable energy standard; rather, it is an additional mandate.
In order to protect some industries, the House bill exempts any “iron mining extraction and processing facility” or “paper mill, wood products manufacturer, sawmill, or oriented strand board manufacturer” that would otherwise be subject to potential rate increases stemming from the standard. The bill also exempts power cooperatives and municipal utilities from complying with the standard, which means that only the four investor-owned power companies serving Minnesota must comply: Xcel Energy, Minnesota Power, Otter Tail Power Co., and Interstate Power & Light.
The Minnesota House and Senate must complete any compromise bill by the May 20th deadline for votes.
On April 10, President Obama fired the starting gun when he submitted to Congress his budget request for the 2014 fiscal year. The budget contains numerous proposals that are intended to make the U.S. "the leader in the clean energy sector and bring about a clean energy economy with new companies and jobs."
According to the White House, the budget would boost funding for work on clean energy technology by 30% over 2012’s enacted level. That amounts to $7.9 billion across all federal agencies, with the lion’s share going to the Department of Energy (“DOE”). The budget earmarks a total of $6.2 billion for DOE projects, including:
- $614 million to “increase the use and reduce the costs of clean renewable power from solar, wind, geothermal and water energy,”
- $80 million to advance clean energy integration into the delivery grid, and
- $282 million to develop the next generation of advanced biofuels.
Perhaps the biggest news to come out of the budget announcement was President Obama’s call for a permanent and refundable production tax credit (”PTC”). The White House believes the permanent PTC would “provide a strong, consistent incentive to encourage investments in renewable energy technologies and to help meet our goal to double generation from wind, solar and geothermal sources by 2020.” Whereas in the past renewable energy developers have been subject to Congress’ yearly vacillations, a permanent PTC would create a more stable environment for the development of wind, solar, and geothermal projects.
Although the budget proposal is an important first step, it’s important to remember that at this point, President Obama’s proposal is just that – a proposal. The document must still jump numerous hurdles in Congress before it crosses the finish line and returns to the White House for his signature.
The Minnesota State Legislature’s attempt to expand the amount of electricity that utility companies secure from renewable energy sources cleared a major hurdle recently, as H.F. 956 was included in the House omnibus energy bill. H.F. 956 proposes to increase Minnesota’s renewable energy standard (“RES”) to 40% by 2030. The current standard requires that Minnesota’s utilities secure 25% of their power from renewable sources by 2025 (30% for Xcel Energy in exchange for nuclear waste storage at Prairie Island).
Although the Senate companion bill, S.F. 901, does not include the same language, the bill includes a 40% by 2030 renewable energy transmission and integration study. Such a study lays the foundation for an expanded RES, possibly as soon as the conference committee.
In addition to the RES expansion, the bills set forth requirements for the creation of a solar electricity standard and an expansion of the use of distributed generation. The solar electricity standard contained in S.F. 901 would require utilities to generate or procure solar electric generation capacity at a minimum percentage (not yet specified) by 2016, 2020, and 2025. Like the current RES, the solar electricity standard would set different values for Xcel Energy. Notably, the solar energy procured for the solar electricity standard could not be used to satisfy the utilities’ obligations under the RES. H.F. 956 seeks to expand the use of distributed generation throughout Minnesota by requiring the Minnesota Public Utilities Commission to initiate a proceeding to establish a generic standard for utility tariffs for interconnection and parallel operation of distributed generation projects. Among other things, the tariff standards must encourage maximum penetration of distributed generation.
Despite the recent success, more hurdles remain for these bills. The bills must pass additional legislative committees, the House and Senate floors, a conference committee, and secure the Governor’s signature. The remaining seven weeks of the 2013 legislative session should provide some interesting developments.
My California colleague Kristen Castaños has written an alert about a recent Fresno County Superior Court decision that denied a challenge to Fresno County's cancellation of a Williamson Act contract to accommodate a solar generating project.
The decision is the first time a court has considered the interplay between the Williamson Act, a California statute that seeks to protect agricultural land, and California’s directive to increase reliance on renewable energy in the state. In rejecting the challenge, the court gave the County substantial deference to determine whether the public interest in developing solar projects outweighs the public interest in protecting agriculture.
In September 2012, all new electricity generation came from solar and wind projects, according to the Energy Infrastructure Update (PDF) issued by the Federal Energy Regulatory Commission’s Office of Energy Projects. Five wind projects totaling 300MW and 18 solar projects totaling 133MW came online during the month.
The Energy Infrastructure Update also noted that nearly half (43.8%) of new generating capacity coming online in 2012 through September involve renewables: 77 wind projects (4,055 MW), 154 solar projects (936 MW), 76 biomass projects (340 MW), 7 geothermal projects (123 MW), 10 water power projects (9 MW), and one waste heat project (3 MW).
The looming expiration of the Section 1603 Treasury Cash Grant and the Production Tax Credit (PTC) is likely a significant driver of this end of year surge. See our October 18 post Economists Weigh in on the PTC Extension for our latest on the PTC.
On October 1, 2012, the Public Service Commission of Utah approved Rocky Mountain Power's Solar Incentive Program, which will support 60 MW of new distributed solar PV resources in Utah over the next five years (2013-2017).
The program will provide approximately $50 million in incentives and will support 60 MW of new distributed solar resources, allocated among three sectors: Residential (systems up to 4 kW), Small Non-Residential (systems up to 25 kW), and Large Non-Residential (systems up to 1,000 kW). Rocky Mountain Power will start accepting applications in January 2013 for the first program year.
For more details about the program, read Laura’s and Julia’s client alert.
At today's open meeting, the Federal Energy Regulatory Commission (FERC) adopted a new rule that may be particularly helpful for variable energy resources (wind and solar) that, in the past, have been hit with pricey imbalance penalties, and for the transmission providers who have struggled to integrate those resources. The new rule adopted today requires transmission providers to provide generators with the option of scheduling transmission service on 15-minute intervals, rather than the typical 60-minute interval. With the shorter scheduling interval, generators will be able to better mitigate imbalance penalties, and transmission providers should be able to maintain reserves that more closely match the variable generation that is expected to be online. The bottom line--cost savings!
FERC also issued a Notice of Proposed Rulemaking (NOPR) in which FERC proposes to revise its policies governing the sale of ancillary services at market-based rates. FERC also proposes to require transmission providers outside of organized markets (e.g. WECC) to take into account resource speed and accuracy in determining regulation and frequency response reserve requirements. That consideration may help to establish a stated need for fast-acting resources, such as certain energy storage technologies. The NOPR also suggests other regulatory changes that, in part, aim to provide energy storage technologies with better access to providing ancillary services.
We will soon issue full clients alerts on the results of today's open meeting at FERC. If you would like to receive an electronic copy of our Energy Law Alerts, please follow this link: Sign Up - Stoel Rives Energy Law Alerts
Pacific Gas & Electric Company (PG&E) announced yesterday that it had issued its 2012 Photovoltaic Program Power Purchase Agreement Request for Offers (“PV PPA RFO”). PG&E seeks to procure PPAs for 50 MW of new photovoltaic resources to be located in PG&E’s service territory.
Copies of the solicitation protocol and related information and materials are now available on PG&E’s website . In its announcement, PG&E advises prospective bidders to "use the current versions of the documents when submitting an offer for this RFO." Offers are due by May 3.
PG&E will host a Participants’ Webinar on April 11 from 10:00 AM to 12:00 PM Pacific time. To register for the Webinar, complete the Webinar Registration Form and return it to PVProgram@pge.com by April 6, 5:00 PM PPT.
For information or questions about PG&E’s 2012 PV PPA RFO, please email PVProgram@pge.com.
By Aaron Barker
The Solar Energy Industries Association (SEIA) reported that the U.S. solar market grew 67% in value in 2010. We have also noticed that the amazing growth in the solar industry is reflected in U.S. patent activity. Because the solar industry covers a wide range of technologies, we looked at a simple example of issued U.S. patents that include the word “solar” in the title. We found that the number of “solar” patents increased 42% in 2009 and 73% in 2010. The chart below shows that the number of “solar” patents was relatively flat during most of the 1990s (hitting a low of 106 patents), increased during 1999-2003 (228 patents), dipped during 2004-2005 to 1998 levels (126 patents), and rose slightly during 2006-2008 to 2004 levels (170 patents). There were 242 patents in 2009 and 419 patents in 2010.
Using broad categories for the “solar” patents that issued in 2010, we estimate that 142 patents cover solar cell technologies, 109 patents cover solar powered devices or systems, 63 patents cover solar panel assemblies, 43 patents cover solar heating or cooling, 18 patents cover power plant technologies, and 17 patents cover mounting or packaging technologies.
The increase in solar-related patent activity is consistent with an increase in overall U.S. patent activity. In the recently published Oregon Patent Report for 2008-2010, intellectual property attorneys at Stoel Rives reported that the number of patents issued to corporate and individual inventors in Oregon rose a healthy 18.1%, compared with drops of 7.5% in 2009 and 4.4% in 2008. Nationally, the number of patents awarded to all U.S. inventors in 2010 rose 27.5%, compared with only a 3.3% increase in 2009 and a 1.8% drop in 2008. Thus, in addition to strong growth in the overall U.S. solar market, at least some of the increase in solar patent activity in 2010 may be attributed to a general increase in companies using the patent system to protect their innovations, the U.S. Patent and Trademark Office’s push to reduce a mountainous backlog, and an uptick in the number of patent applications filed just before the recent economic downturn.
Stoel Rives attorney Heath Curtiss, one of the
co-authors of "Federal Land Issues with Siting
and Permitting" in our Law of Wind, describes
a Bureau of Land Management ("BLM") plan to
protect certain land suitable for renewables
development from the location of mining claims :
As many of our clients with right-of-way (“ROW”) applications pending before BLM know, mining claims located prior to a final ROW grant can prove difficult obstacles to clear in the context of project permitting, finance, and development. Unfortunately for renewables developers, mining claims are easy to locate, and difficult to invalidate. This gives mining claimants leverage vis-à-vis other public land developers. As one might expect, with the recent uptick in renewable ROW applications, we’ve also seen an increase in mining claims. According to BLM, over the last two years, 437 new mining claims were located within wind energy ROW application areas on BLM lands, and another 216 new mining claims were located within solar energy ROW application areas.
In an effort to address such conflicts, on April 25, 2011, BLM published notice of an Interim Rule effective immediately, and a nearly identical proposed rule, that gives BLM the ability to segregate lands included within wind and solar ROW applications, or lands that BLM identifies for potential wind and solar ROWs. Once segregated, such lands would no longer be subject to appropriation under the appropriations laws, including location under the General Mining Law of 1872. Segregation would not, however, explicitly restrict leasing under the Mineral Leasing Act of 1920, or sales under the Materials Act of 1947, presumably because those acts already give BLM significantly more discretion to balance competing uses. Likewise, neither the interim nor proposed rule purport to affect existing mining claims.
The foregoing segregation would take effect once BLM publishes notice in the Federal Register, and would terminate on the earliest of (i) a decision to grant or deny the ROW application, (ii) automatically at the end of the segregation period, not to exceed 2 years from the date of publication, or (iii) upon publication of a notice of termination.
BLM is accepting comments on the interim and proposed rules until June 27, 2011.
FERC Seeks Comments on Regulatory Reforms for Merchant Transmission and Generator Interconnection Capacity
The Federal Energy Regulatory Commission ("FERC") is seeking comments from energy industry participants on regulatory reforms that address how FERC should regulate merchant transmission development and generator interconnection (or lead) lines. Specifically, FERC desires comments on how it should balance the requirements of open access transmission and the needs of project developers.
Merchant transmission and generator interconnection issues have caused a surge of contested FERC proceedings in recent years. In 2009, merchant transmission developers, for instance, were granted the ability to place transmission capacity with anchor tenants prior to making capacity available through an open season. The anchor tenant model was a significant shift in merchant transmission regulation, but, to date, merchant transmission developers have struggled to maintain meaningful anchor tenant arrangements. As a result, more recent filings at FERC have pushed the boundaries of the anchor tenant model, and FERC now seeks to determine through public comment how its open access policies could be further changed to incentivize merchant transmission development.
Generator interconnection lines have also been a popular subject at FERC of late—specifically whether and how interconnection line owners should be granted priority rights to interconnection capacity. This issue is particularly relevant for renewable energy developers who are planning to build generation projects in phases and will rely on having interconnection capacity available to serve later phases when they come online. To maintain priority over competing interconnection requests, FERC has asked generation developers to show they have established milestones for developing the generation phases that seek priority (and to demonstrate progress toward meeting those milestones). Such filings are generally confidential, and thus interconnection line owners from the outside looking in have not been given much insight into what is required to establish priority. FERC's precedent on the issue has also created dissimilar treatment of interconnection owners who are affiliated with open access transmission providers.
On March 15, 2011, FERC staff held a technical conference where the invited speakers shared a wide range of opinions on these issues. With respect to merchant transmission, speakers supported (i) creating a new section to the Open Access Transmission Tariff ("OATT") that would specify the rules for developing merchant transmission and the ancillary services obligations of those developers, (ii) placing AC merchant lines under existing incumbent transmission provider OATTs, (iii) allowing more incentives for anchor tenants, and (iv) having FERC back away from regulating these projects in their early stages. Those who spoke about priority to interconnection capacity shared opinions that included (x) requiring interconnection developers to give public notice of their development intentions and allow others to bid on capacity (a "speak now or forever hold your peace" approach), (y) requiring all interconnection owners to develop and maintain an "OATT light"—a pared down version of the full OATT, and (z) advocating for less regulation of interconnection lines altogether. FERC staff also questioned whether and how FERC should regulate transmission service over interconnection facilities that are shared or jointly owned (e.g., through a Joint Ownership Agreement, Shared Facilities Agreement, or Common Facilities Agreement) directly by generation developers, or indirectly through an affiliate that owns and operates an interconnection line.
Written comments on these issues are due to FERC no later than April 21, 2011.
The Oregon Department of Fish and Wildlife (“ODFW”) posted the final draft rules and draft conservation strategy related to the greater sage-grouse. After years of negotiation and numerous public meetings on the ODFW’s approach, the final drafts are open for public comment. On April 22 they will be presented to the Fish and Wildlife Commission for consideration for adoption.
In March of last year the US Fish and Wildlife Service (“USFWS”) determined that protection of the greater sage-grouse was warranted under the federal Endangered Species Act (“ESA”) but was precluded from listing by the USFWS’s need to take action on species facing more immediate or severe threats. The species is now a candidate for listing, but it is uncertain if or when a formal ESA listing may occur. Oregon, through ODFW’s approach to sage-grouse conservation, joins other western states (e.g., Wyoming) in taking preventative state action, at least in part, to preclude the need for an eventual federal listing.
Both the USFWS determination and the ODFW’s conservation strategy identify energy, and renewable energy development specifically, as posing threats to the specie. The ODFW’s conservation strategy points out that there is great potential for geo-thermal, solar and wind energy in most sage-grouse regions in Oregon, but the same windswept ridges that make for great wind facility siting, for example, may also be important sources of accessible winter forage for sage-grouse.
Among other things, the draft rule would formally adopt the ODFW’s Core Area Approach to Conservation and directs the ODFW to maintain maps of sage-grouse core areas. The rule stops short of directly equating sage-grouse core areas with habitat categories under the Fish and Wildlife Habitat Mitigation Policy. By referencing the ODFW’s conservation strategy, the rule instead outlines micro-siting guidance for development projects (e.g. a wind facility) proposed in identified core areas. As part of the siting process, the ODFW recommends that sage-grouse habitat in core areas be classified as “irreplaceable, essential habitat” and impacts on such Habitat Category I areas avoided. In past iterations of the core area maps, much of eastern Oregon, and southeastern Oregon in particular, was identified as being home to sage-grouse core areas.
The Oklahoma legislature passed three bills (H.B. 2973, S.B. 1787, and H.B. 3028) in 2010 that affect the renewable energy industry. Two have already gone into effect and the third will go into effect on January 1, 2011. A summary of each bill is included below.
The Oklahoma Wind Energy Development Act (the “Act”), H.B. 2973, becomes effective on January 1, 2011 and will be codified in Okla. Stat. tit. 17 §§160.11-17 (2010). The Act includes the following:
- Decommissioning: Decommissioning requirements apply to any wind energy facility entering into or renewing a power purchase agreement (PPA) on or after January 1, 2011. If energy is not being sold under a PPA, the requirements apply to wind energy facilities which commence construction on or after January 1, 2011. The requirements include:
- Restoration: Owners of a wind energy facility must remove wind energy equipment (to a depth of 30”) and restore land surfaces to substantially the same pre-construction condition (excluding roads) within 12 months of abandonment of a project or the end of the useful life of the equipment.
- Cost Estimate and Posting of Financial Security: After the 15th year of operation, facility owners must file a professional estimate of the decommissioning costs together with a financial security (either a surety bond, collateral bond, parent guaranty or letter of credit) to cover such costs. Those failing to so file may incur an administrative penalty of up to $1,500/day.
- Payment Statements and Access to Records: Any owner or operator making payments to landowners based on the amount of electrical energy produced is required to deliver a statement to the landowner, within 10 business days of payment, explaining the payment calculation and a means for the landowner to confirm its accuracy. Landowners have the right to inspect owner/operator records to confirm the accuracy of payments for up to 24 months following payment. Records must be made available for review within the state of Oklahoma.
- Insurance: Owners or operators are required to obtain commercial general liability insurance policy with limits consistent with prevailing industry standards (or a combination of self insurance and excess liability insurance policy), which name the landowner as an additional insured and certificates of insurance must be delivered to landowner prior to commencing construction of the facility.
No Severance of Wind and Solar Rights. Wind and solar right severance was restricted in another Senate bill out of the same session, Oklahoma S.B. 1787. The bill restricts the permanent severing of rights to the airspace above the surface estate for the purpose of developing and operating commercial wind and solar energy conversion systems. Thus wind and solar resource leasing arrangements (broadly defined to include easement and option arrangements) must be made with the legal owner of the surface estate. The bill confirms that wind and solar agreements run with the land and outlines provisions for recording the interest. The bill will be codified in the Okla. Stat. tit. 60 §820.1 (2010) and became effective July 1, 2010 .
15% Renewable Generation Capacity by 2015. The Oklahoma Energy Security Act (the “OES Act”), H.B. 3028, sets a goal that 15% of all installed electric generation capacity within the state be generated from renewable energy sources by 2015. Qualifying renewable energy resources include: wind, solar, photovoltaic, hydropower, hydrogen, geothermal and biomass (including crops, residues, animal waste, MSW and landfill gas). Demand side management can be used to meet up to 25% of the overall 15% goal. Notably the OES Act does not include any provision for the use of renewable energy certificates (RECs) to meet the goal.
Expand Transmission in SW. To better facilitate wind-energy development, the OES Act also directs the legislature to work with the Southwest Power Pool to develop a plan to expand transmission capacity in Oklahoma.
Develop Natural Gas and Add Fueling Stations. Noting the opportunity to develop Oklahoma’s abundant natural gas resources, the OES Act sets natural gas as the preferred choice for any new fossil fuel based electric generation capacity until January 1, 2020. It also sets a goal to develop public CNG fueling stations every 100 miles along the interstate highway system by 2015 and every 50 miles by 2025. The OES Act became effective November 1, 2010 and will be codified in the Okla. Stat. tit. 17 §§801.1-7 (2010).
Following on the heels of a September 2010 report by GTM Research forecasting that the smart grid market in the U.S. will grow more than 70%, from $5.6 billion in 2010 to $9.6 billion by 2015, Smart Grid Oregon today announced the new organization’s first conference to be held on November 9, 2010 at the World Trade Center in downtown Portland.
The conference will feature keynoters Kurt Yeager, Executive Director of the Galvin Electricity Initiative and President and Chief Executive Officer of the Electric Power Research Institute; and Roy Hemmingway, past Chair of the Oregon Public Utility Commission and also past Chair of the New Zealand Electricity Commission.
Smart Grid Oregon is a trade association that was launched in June 2009 and is dedicated to making Oregon a leader in the implementation of Smart Grid technologies and in supporting companies that build and market Smart Grid products and services. The aim of the first Smart Grid Oregon Public Policy Conference is to help public and utility officials, regulators, legislators, city and county governments and other stakeholders in Oregon and the region gain a better understanding of the Smart Grid and policy decisions that will need to be addressed in the coming years.
Stoel Rives is a member of Smart Grid Oregon, and we are a sponsor of the November 9 conference. See you there!
To learn more, go to www.smartgridoregon.org or contact Ashley Henry at Ashley@smartgridoregon.org or 503-866-9191.
I am proud to announce the publication of two white papers that focus on the issues of transmission development and broader issues facing renewable energy. These white papers were written by attorneys at Stoel Rives and were prepared at the request of the Energy Foundation, a partnership of major foundations interested in sustainable energy. The Energy Foundation was launched in 1991 by The John D. and Catherine T. MacArthur Foundation.
Both papers focus on the challenge of developing U.S. transmission infrastructure and capacity, particularly in the West. In The Way Forward: Why Transmission Right Sizing and Federal Bridge Financing Hold the Key to Western Renewable Resource Development, the authors (Marcus Wood, Pam Jacklin, and myself) consider economy-of-scale and environmental impact concepts and their application to the sizing of transmission facilities. The authors also argue for a significant overhaul of current financing and cost recovery mechanisms in order to provide a pathway for greater development of renewable energy resources. You can download a copy of The Way Forward by clicking here.
In Uncork That Transmission Bottleneck: A Legislative and Technological Roadmap for Tapping the West's Vast Renewable Energy Resources, the authors examine broader issues affecting renewable energy development. This white paper proposes a number of policy goals that could drive transmission development in the West and on a national level. You can download a copy of Uncork That Transmission Bottleneck by clicking here.
We hope that you enjoy these papers.
Saturday was a great day for solar energy: the DOE offered two conditional loan guarantee commitments:
- $1.45 billion loan guarantee to Abengoa Solar Inc. for the construction and start-up of a concentrating solar power (CSP) generating facility in Solana, Arizona and a
- $400 million loan guarantee to Abound Solar Manufacturing for the assembly of state-of-the-art thin-film, cadmium-telluride solar panels.
ABENGOA SOLAR: Once operational, the CSP plant will add 250 MW of capacity to the electrical grid using parabolic trough solar collectors and a six-hour thermal energy storage system (the first of its kind in the United States). The plant which will be about 70 miles southwest of Phoenix, will use mirrors to direct sunlight onto receiver tubes that will heat molten salt fluid to over 700°F. The system's heat will turn steam turbines and the thermal energy storage can provide power during cloudy days and evenings. The plant will supply power to approximately 70,000 homes through a long-term PPA with Arizona Public Service Company.
Abengoa Solar estimates the project will employ approximately 1,600 workers during construction, of which 80 will be permanent jobs. As an added benefit, two assembly factories will be constructed on the site, and a new mirror manufacturing facility will be needed to supply more than 900,000 mirrors to the plant.
ABOUND SOLAR: A $400 million conditional loan guarantee has been offered to Abound Solar Manufacturing for the assembly of state-of-the-art thin-film, cadmium-telluride solar panels. The assembly will take place in in Longmont, Colorado, and Tipton, Indiana. Abound estimates that the project will create approximately 2,000 jobs during construction, as well as 1,500 permanent jobs.
Abound’s manufacturing technology was jointly developed by NREL, Colorado State University, and the National Science Foundation and deposits thin films of cadmium-telluride onto glass panels. This technology reduces overall product costs and provides better film quality, efficiency and reliability. Abound anticipates that it will produce millions of solar panels annually (enough panels to support up to 840 MW of new solar power per year) for less than it costs to produce crystalline silicon modules.
Morten Lund reports:
The California Solar Initiative Handbook was updated June 8, 2010. The new version can be found by clicking here.
Of particular interest are changes to Section 2.4 (warranty requirements). These changes are not necessarily substantively significant, but may require some manufacturers and contractors/installers to conform their warranty language in order to ensure continued eligibility for CSI payments.
DOE announced a conditional commitment for more than $1.37 billion in loan guarantees to BrightSource Energy, Inc. in support of the construction and start-up of three utility-scale concentrated solar power plants (CSP) in the Mojave Desert of southeastern California. The loan guarantee is funded under the American Recovery and Reinvestment Act and is predicated on BrightSource meeting financial and environmental requirements before closing on the loan. The Bureau of Land Management is leading a federal review of the project with support from DOE. Pending local, state, and federal regulatory approval, the new plants will generate approximately 400 megawatts (MW) of electricity using the company's proprietary technology. This output would nearly double the existing generation capacity of CSP facilities in the United States.
The three-plant Ivanpah Solar Complex will be located on federally owned land near the Nevada border and will be the world's largest operational concentrated solar power complex. BrightSource will use solar power tower technology, which uses thousands of flat mirrors, or "heliostats" to concentrate the sun's heat onto a receiver mounted at the top of a tower. Water pumped to the receiver is boiled into steam, which drives a turbine to produce electricity. The first Ivanpah plant is expected to begin construction in the second half of 2010 and come on line in 2012. Commercial operation for the second plant is slated for mid-2013, with the third plant following later that year. Once operational, the project will supply power to approximately 140,000 California homes.
Brightsource says the project will create 1,000 temporary jobs and 86 permanent jobs.
On January 27, Arizona Public Service (APS) announced two requests for proposals (RFPs), one for new sources of photovoltaic (PV) solar energy and the other for Arizona-based wind.
The RFP for solar PV seeks proposals for projects that are between 15 and 50 megawatts and that employ commercially proven technology. APS's goal is to procure approximately 220,000 megawatt hours per year from this PV solicitation. Respondents are required to provide proposals for long-term power purchase agreements and/or "turn-key" agreements. The latter are sometimes called BTAs (Build-Transfer Agreements) or DBS (Design-Build-Sell) agreements--however named, APS anticipates that the agreement would require the developer to build the project and transfer it to APS when the project is completed. (As an aside, turn-key agreements that do not transfer the asset until commercial operation require very careful attention to "notice to proceed" clauses and conditions, lest defects in title, permits or some other matter thwart the closing and leave the developer's asset unsold or, worse, stranded.)
In its press release, APS encouraged parties to participate in the photovoltaic RFP bidder's conference on March 12, 2010. Additional information about the conference and the RFP is available online at www.aps.com/rfp. RFP submissions are due April 7, 2010.
On the wind side, APS is looking for wind projects between 15 and 100 megawatts located entirely within Arizona. Respondents are required to provide proposals for long-term power purchase and/or "turn-key" agreements. Interested parties are encouraged to participate in the Arizona-based wind RFP bidder's teleconference on March 17, 2010. Additional information about the conference and the RFP is available online at www.aps.com/rfp. RFP submissions are due April 14, 2010.
The Department of Energy (“DOE”) announced today that the National Renewable Energy Laboratory (“NREL”) will invest up to $12 million in total funding ($10 million from funds allocated to NREL under the American Recovery and Reinvestment Act (“ARRA”)) in four companies - three California and one North Carolina - to take early stage PV and CSP technologies to commercialization.
Each company will receive up to $3 million (and the benefit of NREL’s support and expertise) to take prototype and pre-commercial PV technologies and develop pilot/demo projects or full-scale manufacturing projects. Payment of the awarded $3 million will be made over time as each company completes specified project milestones.
DOE is investing more than $117 million in solar energy through ARRA.
National Renewable Energy Laboratory (NREL) and the U.S. Department of Energy (DOE) announced the release of the Open PV Mapping Project. The Project is a collaborative effort between government, industry, and the public to develop a comprehensive database of photovoltaic (PV) installation data for the United States.
The Project will provide a Web-based resource for users to easily understand the current status and past progress of the PV industry from the data that show current and recent trends of the PV market. Users can also add their own PV installation data, browse PV data input by others, and view statistics. NREL plans to add additional data and use the information to monitor and analyze market growth.
Next week, the Anaheim Convention center hosts Solar Power International, which bills itself as 'North America's largest business to business solar industry event.’ With over 900 exhibitors (Stoel Rives included) and 25,000 attendees expected, there is no doubt that this conference will be one of the largest and most heavily attended solar industry events in the world this year. The conference starts on Monday October 26 with pre-conference workshops and runs through Friday October 30. This year’s keynote speaker is Robert F. Kennedy Jr. the keynote address will take place on Wednesday morning.
If you are attending the conference, please stop by our exhibit booth (No. 1744), which is centrally located in the “PV Cells and Modules” section of the Exhibit floor. Stoel Rives attorneys Howard Susman, Morten Lund, Pat Boylston, Gregory Jenner, Stephen Hall, Kristen Castaños, David Quinby and Adam Walters will be in attendance.
The Department of Energy (“DOE”) announced a new $390 million energy upgrade program under the Energy Efficiency and Conservation Block Grant (“EECBG”) Program that could save $100 million annually in utility bills. DOE is looking for community-scale retrofit projects that will have a significant, long-lasting impact on energy consumption and which can be replicated in communities nationwide.
DOE is also making $64 million available under the EECBG to local governments that were not eligible to receive the formula grants announced earlier this year under the population-based formula.
These programs were announced through a Request for Information (“RFI”) issued today under the competitive portion of the EECBG Program. DOE is seeking public comment until Sept. 28, 2009.
A link to the Request for Information is below. This is not a funding opportunity announcement so no applications can be made at this point. The FOA is expected to be released in early October, following the public comment period.
Today, in recognition that solar energy is a critical factor in the President's clean energy agenda, the U.S. Department of Energy (DOE) announced that $11.8 million ($5 million from the American Recovery and Reinvestment Act) will be deployed to five projects related to the development of solar energy grid integration systems (SEGIS). This follows our earlier client alerts regarding funding opportunities for solar technologies.
SEGIS activity began in 2008 with a partnership between DOE, Sandia National Laboratories, industry, utilities, and universities interested in complete system development. Funded projects are related to the integration of solar technologies into the U.S. electrical grid while maintaining or improving power quality and reliability.
DOE announced funding of the following projects:
PVPowered of Bend, Oregon. Up to $3 million is available to fund a project that optimizes interconnections across the full range of emerging PV module technologies through innovative systems integration. This project includes the following partners: PVPowered, Portland General Electric, South Dakota State University, Schweitzer Engineering Laboratories, and SENSUS.
Petra Solar of South Plainfield New Jersey. Up to $2.9 million is available to fund a project that supports improving reliability and resiliency so that high levels of PV integration can be adapted. This project includes the following partners: Petra Solar, University of Central Florida, and fifteen electric utilities.
Princeton Power of Princeton, New Jersey. Up to $2.8 million is available to fund a project that focuses on lowering manufacturing costs through integrated controls for energy storage and the development of new inverter designs. This project includes the following partners: Princeton Power, Transistor Device Inc, LaGuardia Community College, Idyllwild Municipal Water District, National Oceanographic and Atmospheric Administration, Princeton Plasma Physics Laboratory, Premier Power, SPG Solar, and Spire.
Apollo Solar of Bethel, Connecticut. Up to $1.5 million is available for the creation of innovative inverters using energy storage and two-way communications between solar electrical systems and utilities. This project includes the following partners: Apollo Solar, Saft Batteries, the Electric Power Research Institute, and California Independent System Operator.
Florida Solar Energy Center / UCF. Up to $1.3 million is available to solve technical challenges that impede the deployment of higher PV penetration levels in larger scale systems. This project includes the following partners: Florida Solar Energy Center, Satcon Technology Corporation, SENTECH, Inc., Cooper Power Systems EAS, Northern Plains Power Technologies, and Lakeland Electric Utilities.
On July 1, 2009, Washington State’s Department of Community, Trade and Economic Development (“CTED”) issued application guidelines and forms for its State Energy Program (“SEP”) (available by clicking here). The American Recovery and Reinvestment Act of 2009 (the “Recovery Act”) provided $60.9 million in new funding for Washington’s SEP. Subsequently, the Washington Legislature allocated $38.5 million to CTED to administer a loan and grant program for energy efficiency and renewable energy program (see our client alert, available here, regarding the legislative action).
Eligible energy efficiency, renewable energy, and clean energy projects may be eligible for SEP funding between $500,000 and $2 million.
Eligible energy efficiency projects are those that use technologies that have been deployed at commercial scale that result in the reduction in energy consumption through increases in the efficiency of energy use, production, or distribution, and high-efficiency cogeneration. Ineligible projects are those that are eligible for Recovery Act Funding for community wide urban residential and commercial energy efficiency upgrades as described in (i) Chapter 379, Laws of 2009; (ii) Low income weatherization projects and programs which are eligible for funding through the state’s low-income weatherization program; (iii) Loans support to financial institutions for energy efficiency projects as described in Chapter 379, Laws of 2009; (iv) state energy efficient appliance rebates; and (v) green jobs training as described in Chapter 536, Laws of 2009.
Eligible renewable energy projects are those that are located in Washington and use existing commercial scale technologies that generate liquid fuels, process heat or electricity using algae, bark, biodiesel, biomass, biosolids, food waste, fresh water, gas from sewage treatment facilities, landfill gas, geothermal, pulping liquors, sawdust, solar, hydrokinetics, wind, wood chips and various other waste products. Ineligible projects include those that use the following feedstocks: municipal solid waste, wood from old growth forests, and chemically treated wood.
Eligible clean energy innovation projects include are those that offer innovative new technologies or service delivery models for energy efficiency, renewable energy, or other areas of clean energy. Projects must have a solid chance at commercial scale deployment within two to three years. Ineligible projects include carbon sequestration projects, lab scale projects, and those excluded under federal SEP guidelines.
Interested parties must file a notice of intent to apply by July 27, 2009 at 5:00 p.m. Pacific.
Full applications are due on August 17, 2009 at 5:00 p.m. Pacific.
Information workshops will be held on July 13, 14, 15, and 16. Click here for the specific dates and times. I will be attending the July 13 workshop in Everett, WA. An informational webinar will also be held on July 23.
Today, the U.S. Department of Energy (“DOE”) announced new funds of up to $10.5 million to inform and educate local governments nationwide about solar energy. As part of the Solar America Cities program, a joint effort with 25 cities dedicated to increasing their use of solar energy, the DOE has assembled educational materials about the benefits and value of solar energy. The DOE will now work with outreach organizations to share these materials and tools with local government officials, with the aim of speeding up the implementation of solar energy. The application deadline is October 15, 2009, with selections expected to be announced no later than December 15, 2009.
For more information, click here for our recent Energy Alert.
The U.S. Interior Department has instigated initiatives to accelerate the development of solar energy on Western lands. About 670,000 acres currently administered by the Bureau of Land Management (“BLM”) in Arizona, California, Colorado, Nevada, New Mexico, and Utah will be evaluated for the development of large-scale solar energy production. These areas of land will be reserved for solar projects producing 10 megawatts or more of electricity and the goal is to fast-track the permit applications.
Each piece of land is at least 2,000 acres and has been selected for its solar resources, slope, proximity to roads and transmission lines or designated corridors. The evaluation will be funded with Stimulus monies under an ongoing federally-funded evaluation of solar energy development on public lands in six Western States. The evaluation should be completed in late 2010.
Today, San Diego Gas & Electric (SDG&E) issued a Request for Offers seeking eligible renewable resources that the utility will use to meet its California Renewable Portfolio Standard requirements. Respondents may submit one or more of three alternative proposals:
- Power Purchase Agreement (PPA). Respondents are asked to propose a 10, 15, or 20-year PPA for capacity and/or energy, but SDG&E will nevertheless consider proposals with shorter or longer durations. Eligible Resources must be delivered to a point within California and must be begin deliveries sometime between 2010 and 2013.
- PPA with Buyout. Respondents offering PPAs may also submit an option price that SDG&E may exercise to purchase the resource as well as associated environmental attributes, land rights, permits, and other licenses upon conclusion of the PPA term. This alternative is limited to resources located in San Diego County, parts of Orange County within SDG&E's service territory, or Imperial Valley areas. Like respondents offering under the PPA alternative, respondents interested in offering resources under the PPA with Buyout alternative must begin delivering energy and/or capacity between 2010 and 2013.
- Turnkey Facilities. Respondents to the RFO may also propose to develop and construct a new renewable energy generation facility that SDG&E will acquire. SDG&E is proposing the same locational requirements that apply to PPA with Buyout projects.
A limitation that applies to all respondents is that resources located in SDG&E's service territory must be no smaller than 1.5 MW, and resources outside of SDG&E's service territory must be no smaller than 5 MW.
This RFO may be a great opportunity to transact with SDG&E as it endeavors to comply with California's ever-increasing RPS standards. SDG&E will hold two pre-bid conferences: one in San Diego on August 5, 2009, and the other in El Centro on August 12, 2009. Those interested in attending a pre-bid conference should register by July 31.
For more information, click here: SDG&E 2009 RFO Info
On May 27, 2009, President Obama announced that the Department of Energy ("DOE") is to provide $117.6 million to support the widespread commercialization of clean solar technologies and to scale up U.S. solar manufacturing and production. The funds are intended to promote partnerships between DOE's national laboratories, universities, local government, and the private sector to promote and improve the U.S. solar industry. The DOE issued two funding opportunity announcements ("FOA") for high-penetration solar deployment and market transformation and one program announcement related to concentrated solar power research and foundational photovoltaics.
For more specific information, see this recent alert.
As technologies develop and commercial acceptance grows, solar photovoltaic installations are increasingly providing a viable alternative for the small-scale distributed generation of electricity to supplement more traditional polluting sources. The growth of the solar industry in the United States over just the past two years has been phenomenal. Having a rooftop solar photovoltaic installation on corporate headquarters, major distribution centers, and other high-profile real estate has become a significant way fro major global corporations to demonstrate their commitment to a cleaner environment. New sources of investment capital are flooding into this niche, and power buyers large and small have been drawn to solar as a way of demonstrating their independence from traditional generation sources and desire to play a part in moving the United States toward a more independent future. States across the country have moved to fill the federal leadership vacuum, in many cases enacting renewable portfolio standards and state renewable energy tax credits, which are critical to the continuing development of our solar resources. The industry is vibrant.
Nonetheless, distributed generation solar projects, like other renewable generation projects are subject to a plethora of real property issues, regulatory and permitting requirements, interconnection, and power purchase negotiations, financing challenges, tax matters and construction contracting.
Recognizing these challenges, and as part of our commitment to the growth and success of the renewable energy industry, Stoel Rives developed its first Law of ... publication in 2003. We now introduce Lex Helius: The Law of Solar Energy, the newest installment in our continuing efforts to provide easily accessible information for individuals and companies interested in growing U.S. renewable energy resources. This guide contains insights we have gained from practical experience assisting participants in numerous solar photovoltaic projects covering a diverse range of sizes and installations, as well as from 15 years of experience serving the U.S. renewable energy industry.