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.
"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.
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.
For those companies owning generation on the Bonneville Power Administration system, mark your calendars for March 15, 2014. That's the day by which you must submit your facility displacement costs for Bonneville's implementation of its Oversupply Management Protocol (aka Environmental Redispatch) that provides compensation for certain generator curtailments. The failure to submit facility displacement costs will result in a displacement cost of $0.00 per MWh.
So begin registering your facility with Bonneville now at https://oversupply.accionpower.com so that you are prepared for when Bonneville begins accepting displacement cost information on February 28.
Ralls Corp., a privately-held company owned by executives of the China-based heavy machinery manufacturing conglomerate Sany Group, recently filed an appeal in its ongoing effort to avoid President Obama’s order requiring the company to divest itself of its interest in four wind farms in Oregon. We have previously reported on the order, which was issued by the president on the recommendation of the Committee on Foreign Investment in the U.S. (CFIUS) and followed a similar CFIUS order. The CFIUS order was withdrawn following issuance of the executive order. Our earlier articles can be found at http://www.lawofrenewableenergy.com/tags/ralls-corp/.
On February 7, Ralls Corp. filed an appeal of the D.C. Circuit Court’s October ruling that Ralls Corp. was not deprived of due process and that it was not entitled to know the specific basis for the executive order. The appeal asserts, among other things, that the district court erred in finding that Ralls Corp. has no constitutionally protected interest in the wind projects and in granting undue discretion to the president to prohibit a transaction on national security grounds. Ralls Corp. takes particular issue with the federal government’s failure to state with specificity the factual basis for the orders and to give Ralls Corp. an opportunity to address and rebut such a statement.
Separately, the US government has initiated a civil action to force the sale of the wind projects, which are located adjacent to a US Naval facility that is believed to be used to test unmanned drones and other electronic warfare equipment, as required by the executive order.
A successful outcome for Ralls Corp. seems unlikely, given the deference the judicial branch has historically given the executive branch with respect to matters of national security. The ongoing dispute continues to serve as a reminder of the extensive authority of CFIUS and the president to intervene in transactions to protect national security interests and, therefore, the importance of notifying CFIUS of transactions that may concern national security.
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.
With the holidays behind us and the cheer and reverie of the New Year trailing off, wind developers in Idaho may be realizing that the Federal Energy Regulatory Commission (FERC) left a lump of coal in their stockings on Christmas Eve. On December 24, FERC agreed to dismiss an historic legal action that it had taken to enforce the Public Utility Regulatory Policies Act of 1978 (PURPA) against the Idaho Public Utilities Commission (IPUC) on behalf of Qualifying Facility (QF) wind developers who have been beaten up by numerous decisions coming out of the state agency over the past several years. FERC had never before sought to enforce PURPA against a state agency, but the IPUC apparently found FERC’s tipping point.
In exchange for its agreement to dismiss this first-of-its-kind action, FERC extracted a simple acknowledgement of questionable value from the IPUC: “The Idaho PUC acknowledges that a legally enforceable obligation may be incurred prior to the formal memorialization of a contract to writing.” And that is as far as their substantive agreement goes. In other words, the IPUC acknowledges that a hypothetical situation may occur, without agreeing to the all-important question of when that situation does occur. The agreement signals an apparent policy change at FERC, and it also leaves QF wind developers on their own, once again, to enforce PURPA in protracted litigation in federal court, i.e., without a viable option.
For those keeping score, there was none in this dispute: FERC threw in the towel before the first bell.
Xcel Energy, the nation’s leading wind power utility, announced yesterday that it will add three large wind farms to its wind energy portfolio. The 600 megawatt increase is the utility’s single largest increase in its Upper Midwest service area.
The 33 percent increase will augment Xcel’s existing 1,800 megawatts of wind capacity and allow it to power an additional 180,000 homes via wind. The utility estimated that the increase in wind capacity will allow customers to save $180 million over the projects’ 20-year life span compared to electricity generated from Xcel’s existing power plants.
A major reason for the savings is the extension of the federal production tax credit. As long as the three projects begin construction by December 31, 2013, the projects will receive a 2.3 cents/kWh subsidy for the first ten years of operation.
In addition to providing cheaper electricity, Xcel’s planned increase in its wind portfolio will help it achieve its 31.5% mandate under Minnesota’s renewable portfolio standard. The standard requires that eligible renewable electricity account for 31.5% of Xcel’s total retail electricity sales in Minnesota by 2020.
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 IRS recently announced that the production tax credit (“PTC”) will be more valuable in 2013. In the April 3, 2013 edition of the Federal Register, the IRS issued an important piece of guidance for those in the renewable energy field, stating that the PTC incentive would increase for the 2013 calendar year, from 2.2 to 2.3 cents per kWh for fully qualifying energy sources, while remaining at 1.1 cents per kWh for sources like open-loop biomass and incremental hydro. The IRS last adjusted the PTC in 2010, when it increased the incentive to 2.2 cents per kWh. Prior to 2010, the IRS raised the incentive from 2.0 cents per kWh to 2.1 cents per kWh in 2008.
In addition to the increase, the IRS announced that because the 2013 reference price for electricity produced from wind (4.53 cents per kWh) did not exceed 8 cents when multiplied by the inflation adjustment factor (1.5063), the eventual phaseout of the credit would not begin in 2013.
While an increase in the PTC incentive will surely be greeted as good news by developers, many were hoping to have received guidance by the end of the first quarter on the new tax rules that were a part of the PTC extension. Historically, a project’s qualification was determined by the date the project was placed in service. Now, qualification is based on the date construction begins; that is, as long as construction begins before the end of the calendar year, the project is eligible for the PTC. Guidance from the federal government is necessary on what suffices for beginning construction. Until they hear otherwise, developers must operate under the assumption that they need shovels in the ground by December 31.
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.
There has been a new development in the effort by Ralls Corporation, a company owned by two Chinese nationals, to challenge President Obama’s September 2012 order requiring it to divest its interests in four wind projects in Oregon and to remove any equipment and infrastructure it had placed on the sites of the proposed projects. The President’s order, issued pursuant to section 721 of the Defense Production Act of 1950 (“Section 721”), had cited unspecified national security risks as the reason for blocking Ralls Corporation’s acquisition of the wind projects, but the sites of the four proposed projects are near or within restricted airspace of U.S. Naval Weapons System Training Facility Boardman.
On Friday, U.S. District Judge Amy Berman Jackson ruled that she could not overturn President Obama’s order. In her opinion, Judge Jackson said that the law "is not the least bit ambiguous about the role of the courts: 'The actions of the president . . . and the findings of the president . . . shall not be subject to judicial review.'" Therefore, the judge declined to review the President’s findings on the merits. However, she did determine that the court has jurisdiction to determine whether the President followed proper procedures in implementing Section 721. The judge will rule on that due process issue following further briefing by the parties. If Ralls Corporation wins on the merits of the due process claim, it may be entitled to hear the reasons for the President’s decision to block the acquisition of the wind projects.
*Update: Ralls Corp reacted to Judge Jackson's ruling by insisting they would "persist in the lawsuit to the end and will appeal to the circuit court or the supreme court [sic] of the United States if necessary." See here for more of the company's reaction.
The Committee on Foreign Investment in the United States (CFIUS) recently issued its 2012 Annual Report to Congress. My colleague CJ Voss has summarized some of the report's key findings.
CFIUS is charged with reviewing acquisitions of U.S. businesses for national security implications. As we reported last fall, President Obama blocked Chinese-owned Ralls Corporation’s acquisition of wind farm projects in Oregon following intervention by CFIUS in the deal.
According to CJ, the report provides important insights for foreign companies considering investment and M&A transactions that could raise national security considerations, including:
- CFIUS believes foreign governments or companies likely have a “coordinated strategy” to acquire U.S. companies involved in research, development and production of critical technologies
- Filings with CFIUS have increased 70% since 2009
- Filings involving Chinese buyers have increased
- CFIUS has imposed various mitigation measures on transactions
- Certain industry sub-sectors accounted for more than half of all filings between 2009-2011
On October 29, 2012, the U.S. Justice Department filed a motion to dismiss the lawsuit filed by Ralls Corp (“Ralls”), an affiliate of Chinese-owned Sany Group, challenging President Obama’s September 28, 2012 order that blocked four planned Oregon wind projects on national security grounds. See our previous posts for more background on the Ralls Corp. v. Committee on Foreign Investment in the U.S. case.
In its filing, the Justice Department argued the Defense Production Act prohibited judicial review of presidential orders that suspend or prohibit the acquisition of a U.S. business by a foreign person. “Neither the president’s findings nor his actions in the presidential order fall outside his extremely broad discretion, and Rall[s]’s constitutional claims are nothing more than disguised challenges to his exercise of that discretion,” wrote U.S. Attorney Joel McElvain in the filing.
Ralls has argued the Presidential Order could cost the company $20 million in lost design and construction costs. Ralls also argues it will also lose $25 million in federal tax incentives if the wind projects are not placed in service by December 31, 2012.
Stay tuned to Renewable + Law blog for more developments in this case.
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.
Via my colleague Thomas Braun:
Earlier this week, the Minnesota Court of Appeals weighed in on a long-running dispute between the City of Orono and city resident Jay Nygard over the installation of a small wind turbine on Mr. Nygard’s property. The dispute began two years ago when the city denied Mr. Nygard a permit on the ground that wind turbines are not listed as a permitted, accessory or conditional use in the city’s zoning ordinance. Despite the denial of his permit application, Mr. Nygard proceeded to construct the wind turbine anyway. After discovering the turbine, the city commenced an action in the district court for a declaratory judgment that the wind turbine did not comply with the city’s zoning ordinance. Mr. Nygard followed with his own action challenging the city’s denial of his application. The district court ruled in favor of the city and concluded that the city’s zoning ordinance unambiguously set forth an exhaustive list of lawful accessory uses, which does not include wind turbines. Mr. Nygard appealed.
In its ruling, the Minnesota Court of Appeals disagreed with the district court’s interpretation of the city ordinance. The court held that the language of the ordinance was not definitive as to whether the list is exhaustive and, since the city has allowed numerous uses in the past that are not expressly mentioned in the city ordinance, such as flagpoles, basketball hoops, and clotheslines, the city could not single out wind turbines. Thus, the court held that the city erred in denying Mr. Nygard’s permit application.
This decision is the latest saga in the debate in Minnesota over wind energy siting standards and setbacks. This case demonstrates the particular challenges of siting wind turbines (even small ones) in a an urban area without the benefit of an ordinance that provides clear standards.
Following up on our posts on the subject, I had the chance to speak with Colin O'Keefe of LXBN regarding President Obama's blocking of a Chinese-owned wind energy project out of concerns for national security. In the brief interview, I explained what exactly happened and whether or not the companies involved have any kind of legal recourse.
Ralls Corp. (“Ralls”), a company owned by two Chinese nationals and affiliated with the Sany Group, a global heavy manufacturing company (“Sany”), amended its lawsuit on Monday in an effort to overturn President Obama’s executive order requiring Ralls to divest itself of four 10 megawatt wind projects under construction near restricted airspace in Oregon (the “Oregon Projects”). Prior to the divestiture, Ralls is required to dismantle and remove all physical structures that have been installed on the site of the Oregon Projects, including at least 12 concrete foundations that have been fully or partially constructed. Citing national security concerns, the executive order gives the multi-agency Committee on Foreign Investment in the United States (“CFIUS”) broad authority to enforce its terms, including by accessing the premises and facilities of Ralls, the Oregon Projects, and Sany.
In response to both the executive order and a prior order issued by CFIUS, neither of which identify the specific nature of the national security risks arising from Ralls’s ownership of the Oregon Projects, Ralls alleges that CFIUS and the President exceeded their statutory authority by issuing the orders and asserts constitutional challenges to the orders, including that the orders violated the Due Process Clause of the Fifth Amendment. In its complaint, Ralls "emphatically denies that its acquisition of the [Oregon Projects] was intended to or will have or raise any risks or threats regarding the national security of the United States, and it denies that any credible evidence of such intent or effect exists.” The complaint goes on to assert that the development of the Oregon Projects will benefit the U.S. by creating jobs and providing a source of clean, renewable energy, albeit a small enough source of energy so as not to significantly impact the local utility’s supply one way or another. The complaint notes that, if constructed, the Oregon Projects would constitute about 0.37% of the utility’s total generating capacity. CFIUS and the President are expected to defend the orders which, according to the authorizing statute, are not subject to judicial review.
President Obama issued an order on Friday blocking the construction and ownership of a wind project by Ralls Corporation (“Ralls”), due to national security concerns including “credible evidence” that Ralls or its affiliates, including the Sany Group (“Sany”), “might take action that threatens to impair the national security of the United States.” Ralls was in the process of developing a proposed 40-megawatt wind project in Oregon, through its acquisition of four Oregon limited liability companies (the "Oregon Projects"). The President’s order imposes numerous requirements on Ralls, its two owners, both of whom are Chinese nationals, and Sany, including:
- within 90 days, Ralls must divest of all interests in the Oregon Projects and the assets of the Oregon Projects;
- within 14 days, Ralls and Sany must remove all structures and installations of any kind (including concrete foundations) on the Oregon Projects’ property, and the owners of Ralls must provide CFIUS with a signed statement certifying that such requirements have been met;
- Ralls, Sany and any of their affiliates and representatives may not access the site, except for U.S. citizens contracted by Ralls or Sany and approved by CFIUS, who may access the site solely for the purpose disassembling the facility;
- Sany, Ralls, and the owners of Ralls may not sell or facilitate the sale of any Sany equipment for use at the Oregon Projects’ sites, and
- a sale of the Oregon Projects or their assets may not be completed until all structures and installations have been removed, Ralls notifies the Committee on Foreign Investment in the United States (“CFIUS”) in writing of the intended buyer or recipient, and CFIUS does not object.
Although the order does not specify the basis of the concern, it is likely due to the proximity of the Oregon Projects to a U.S. Navy facility that conducts training missions with unmanned drones and electronic-warfare planes. In response, Sany has accused the President of electioneering, according to a report in WindPower Monthly, and Sany may continue to pursue a legal challenge to the order. This may prove to be an uphill battle for Sany, given that the Defense Production Act bars judicial review of presidential orders issued upon recommendation by CFIUS. In light of the presidential order, foreign investors should consider making CFIUS approval a condition to closing under any agreement by which they acquire US energy assets, particularly if the acquisition involves a project located near military facilities and regardless of whether the project or company has defense-related contracts or owns sensitive information.
For more background, see our prior post regarding Ralls’s lawsuit in response to the initial CFIUS mitigation measures: http://www.lawofrenewableenergy.com/2012/09/articles/wind-energy/cfius-intervenes-in-chineseowned-wind-project/.
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
On May 3, 2012, The Detroit Edison Company (DTE Energy) issued a Request for Proposals (RFP) seeking approximately 100 megawatts (MW) of nameplate rated capacity or approximately 300 gigawatt-hours (GWh) of annual supply (including associated RECs) from wind energy systems that will have a commercial operation date before December 31, 2013. DTE expects to contract for the output of the wind energy systems through a 20-year power purchase agreement (PPA).
The RFP itself can be found here, and additional important information concerning the RFP can be found here. DTE’s contact for this RFP is Lori Taylor-Wallace, email@example.com, 313-235-8532.
After years of uncertainty, the Wisconsin legislature allowed statewide wind energy siting rules to go into effect today. The new rules (known as “PSC 128”) require wind turbines to be located at least 1,250 feet from the nearest residence and at a distance 1.1 times the height of the wind turbine from the nearest property line. Cities, villages, towns, and counties are prohibited from enacting an ordinance imposing more restrictive requirements than the statewide rules.
In 2009, the legislature directed the Wisconsin Public Service Commission (“PSC”) to develop rules that limit the restrictions local governments may impose on wind energy projects. The purpose of these rules was to ensure consistent local procedures and regulation of wind energy. On December 27, 2010, the PSC adopted the final wind energy siting rules (Wisc. Admin. Code Ch. PSC 128). But on March 1, 2011, the day the rules were to take effect, the legislature’s Joint Committee for the Review of Administrative Rules voted to suspend PSC 128. This year, the legislature considered a proposal to indefinitely suspend the rules, but adjourned yesterday without taking action. As a result, PSC 128 automatically became effective today.
While PSC 128 was in limbo, the legislature considered a proposal that would have imposed much more stringent setback requirements (1,800 feet from the nearest property line). The American Wind Energy Association said that these setbacks essentially would have killed the commercial wind industry in Wisconsin. News reports suggest that the uncertainty over siting rules caused several wind projects in the state to be suspended or cancelled over the last year. But with PSC 128 now in effect, Wisconsin appears to be open for wind energy business again.
With the end of 2011 drawing near, many renewable energy developers are seeking to qualify their projects for the Section 1603 cash grant. Developers continue to try to understand the complexities surrounding the grant requirements, especially the determination of when projects are considered to have met the “beginning construction” requirement.
On August 24, I'll moderate a Law Seminars International (LSI) Telebriefing on Section 1603, featuring Stoel Rives partner Greg Jenner and Victoria McDowell, the Compliance Program Manager, Section 1603 Program, U.S. Department of the Treasury.
The TeleBriefing will take place from 10 AM – 11 AM Pacific Time/ 1 PM -- 2 PM Eastern Time. During the briefing, attendees will learn how to meet the “beginning construction” test and receive clarification from the Treasury Department on project requirements. We'll also discuss the fate of projects that fail to qualify for the cash grant.
Registration is available online through Law Seminars International.
Stoel Rives Partners to Present Wind Project Development Case Study at Chinese Wind Conference in Beijing
Stoel Rives Partners Alan Merkle, Ed Einowski and Michael Mangelson will participate in the upcoming Workshop on Investment in U.S. Wind Energy by Chinese Companies, held in Beijing, China on June 30, 2011.
The opportunities for mutually beneficial cooperation between U.S. and China wind power industries have become increasingly profitable. Now more than ever it’s important for key players on both sides to understand and evaluate where their best prospects lie, as many basic business assumptions can become lost in translation.
This workshop, organized by the Chinese Wind Energy Association (CWEA), the U.S.-China Energy Cooperation Program (ECP) Wind Power Working Group (WPWG), and the National Energy Administration (NEA), gathers wind experts from across the U.S. and China to discuss the globalization of the Chinese wind energy industry, strategies for undertaking M&A transactions in the U.S., and a variety of case studies based on wind energy development projects.
Stoel Rives attorneys prepared their own case study, which will be presented during the workshop by Alan Merkle. Case Study: Development of a Wind Project in California, is based on a hypothetical 200 MW wind development project in Southern California. The case study covers the legal framework for a project of this scale, including real estate, permitting, transmission and interconnection, power purchase agreement, renewable energy credits, turbine supply and balance of plant agreements, and financing. It is available as a PDF for download in English and Chinese.
Ed Einowski will provide workshop attendees with a presentation titled Setting the Stage for Investing In U.S. Renewable Energy Projects: The Business and Legal Environments. The PowerPoint presentation is available as a PDF for download in English and Chinese.
The Stoel Rives Law of Wind Energy (now in its 6th edition) is also available for download in both English and Chinese editions here.
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.
Stoel Rives partner Bev Pearman reviewed the complaint filed Monday in American Tradition Institute, et al., v. Colorado and prepared this analysis:
On April 4, 2011, the American Tradition Institute (“ATI”), the American Tradition Partnership (“ATP”), and Rod Lueck filed suit in the U.S. District Court for the District of Colorado arguing that Colorado is unconstitutionally discriminating against out-of-state renewable energy producers. ATI is a nonprofit organization “dedicated to the advancement of rational, free-market solutions to America’s land, energy, and environmental challenges,” and ATP is a lobbying organization “dedicated to fighting environmental extremism and promoting responsible development and management of land, water, and natural resources in the Rocky Mountain West and across the United States.” Rod Lueck is a member of ATI and ATP.
Colorado’s renewable energy standard (“RES”) states that by 2020 the state’s two major investor-owned utilities must get 30 percent of electricity sold from recycled or renewable resources. Renewable energy resources are “solar, wind, geothermal, biomass, new hydroelectricity with a nameplate rating of ten megawatts or less, and hydroelectricity in existence on January 1, 2005, with a nameplate rating of thirty megawatts or less.” “Fossil and nuclear fuels and their derivatives” are not “eligible energy resources” for complying with the RES. Additionally, each kilowatt of electricity generated in Colorado from certain recycled or renewable sources is given an enhanced value of one and one-quarter kilowatt-hours for purposes of meeting the mandated standards.
Plaintiffs raise both a sweeping Commerce Clause claim and a more focused Commerce Clause claim. The sweeping claim is that the statutory scheme is unconstitutional because it discriminates against non-renewable generation resources, both in-state and out-of-state, with plaintiffs alleging that such non-renewable generation is “legal, safer, less costly, less polluting and more reliable than renewable generation. A more focused claim is that the statutory preference given to in-state renewable electricity establishes a “market-bias against otherwise qualifying renewable sources located outside of Colorado and an inflated cost of complying with the RES requirements.”
Plaintiffs’ Commerce Clause claim is grounded in a U.S. Court of Appeals for the Tenth Circuit’s decision in KT&G Corp. v. Attorney General of the State of Oklahoma, 535 F.3d 1114, 1143 (10th Cir. 2008), which says a state may violate the dormant Commerce Clause by:
· Discriminating against interstate commerce in favor of intrastate commerce, unless “the discrimination is demonstrably justified by a valid factor unrelated to economic protectionism;” or
· Imposing “a burden on interstate commerce incommensurate with the local benefits secured;” or
· Creating mandates with the “practical effect of extraterritorial control of commerce occurring entirely outside the boundaries of the state in question.”
We expect that Colorado will vigorously defend the RES as being constitutional because its interest in promoting renewable energy generation is an important policy choice. Plaintiffs are attacking that position head-on, however, by challenging the policy of favoring renewable resources, particularly wind energy. They allege that wind energy is not reliable, causes more pollution due to the cycling of coal and natural gas plants during times when wind generation is not possible, and drives up utility costs for consumers. They do not attack other forms of renewable energy as vociferously, but still argue that any scheme favoring renewable resources over other energy sources burdens interstate commerce and violates the Commerce Clause.
The more focused claim (based on the preference given in-state renewable resources) is similar to a Commerce Clause challenge was brought nearly a year ago in Massachusetts by TransCanada Power Marketing, Ltd. (“TransCanada”). The Massachusetts suit did not challenge the policy of promoting renewable energy over non-renewable energy sources. It instead focused on renewable energy mandates and incentives favoring in-state generation. We do not know what arguments Massachusetts would have raised in defense of its program because the case was stayed after the state suspended the regulation underlying the statute in question. It issued emergency regulations, which were later adopted as final regulations, but the statute that establishes the challenged policy has not been amended. On April 1, 2011, the Alliance to Protect Nantucket Sound, an advocacy group that is leading the opposition to the Cape Wind project, filed a motion to intervene in that proceeding. It argued that TransCanada does not represent the interests of Massachusetts ratepayers. Their economic interests are allegedly harmed because the program at issue discourages utilities from entering long-term contracts with out-of-state generators, which has the effect of reducing out-of-state competition and increasing the cost of renewable energy for ratepayers.
The outcome of both of these cases could have far-reaching effects on other state’s RESs and renewable portfolio goals (RPGs). If the plaintiffs are successful with their claims, then the states with RESs and RPGs may have to modify their standards so they are not discriminating against out-of-state renewable energy generators. As we have noted before, the RESs with regional preferences may not be as much at risk. A key question that the courts have yet to answer are whether the RESs and RPGs create protectionist barriers to interstate trade. Check here for regular updates as these groundbreaking cases moves forward.
Today, the State Affairs Committee of the Idaho House of Representatives rejected H265, the bill that would impose a two-year moratorium on new wind projects in the state, by a vote of 11-8. Discussions at the hearing suggest that at least some of the bill's opponents believed the rapid development of wind in the state should be addressed by individual counties, rather than through a statewide moratorium on development. Although it appears that the bill will not make it out of committee, it cannot be considered dead. The bill may yet be rewritten in a process known as "gutting and stuffing" and brought up again this legislative session. For now, though, wind-industry advocates are breathing a sigh of relief.
For more information on H265, see Teresa Hill's blog from last week.
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).
The Idaho Public Utilities Commission (PUC) has issued a straw man proposal that lays out plans to revise the surrogate avoided resource (SAR) methodology used to calculate avoided cost rates for wind generators. The "avoided cost" is the price paid to Qualifying Facilities that are selling power to Idaho utilities under the Public Utility Regulatory Policies Act (PURPA).
The PUC included six cost categories in the wind SAR: capital costs; fixed and variable O&M costs, transmission costs; tax credits; wind integration; and forecasting costs. The PUC assumed transmission costs of $1.90/kw-month, production tax credits at $0.021/kWh, a $0.00 REC premium, and wind integration at $6.50/MWh. With those inputs and others, the PUC arrived at 20-year levelized wind rates for a 2010 project as follows:
|Utility||Wind SAR||Gas SAR|
The PUC proposed that where the Wind SAR is higher than the Gas SAR, a wind developer may choose whether to sell power at the wind or gas rate. If the wind developer opts for the latter, it retains ownership of RECs. If the wind developer opts for the former, RECs go to the utility. However, when the Gas SAR is higher than the wind SAR, wind developers would only be eligible for the wind SAR, meaning that the utility would automatically receive RECs under a PPA. Non-wind projects would be entitled to the gas SAR when the gas rate is higher, and RECs would remain with developers.
The PUC is accepting written comments on the straw man proposal until November 23, 2010.
The Upper Midwest Transmission Development Initiative (UMTDI) issued its final report last week on transmission planning and cost allocation issues associated with delivering renewable energy from wind-rich areas to the region’s customers. Through UMTDI, the governors of Iowa, Minnesota, North Dakota, South Dakota, and Wisconsin collaborated to identify six renewable transmission corridors that could serve as the primary pathways to move thousands of megawatts of wind power. This buildout would cost an estimated $3 billion and serve as a backbone for future energy needs in the five-state region and potentially further east.
Considering the significant cost and shared benefits of regional transmission development, UMTDI also developed a set of general cost allocation principles. This work occurred in parallel and with similar goals to the development of the Midwest ISO’s multi-value project cost allocation proposal filed with the Federal Energy Regulatory Commission in July (Docket No. ER10-1791-000). UMTDI is deferring further development of its cost allocation principles while it monitors the progress of the Midwest ISO’s tariff filing. UMTDI does not take any position on the tariff filing, but acknowledges that construction of transmission lines in its six corridors would be very difficult without a cost sharing mechanism.
UMTDI’s renewable transmission corridors are based on the Midwest ISO’s estimate that about 8,600 MW of new renewable capacity will be needed in the region by 2025 to serve the renewable energy standards and goals of these five states. The group identified twenty “wind zones” where it would be most efficient to develop wind power based on available wind resources, existing wind generation, existing interconnection queue requests, and local geography. The six transmission corridors were chosen as the best general areas for transmission lines to move wind energy from the wind zones to load centers in a cost-effective manner.
Sens. Jeff Bingaman (D-NM) and Sam Brownback (R-KS), with Sens. Byron Dorgan (D-ND), Susan Collins (R-ME), Tom Udall (D-NM), Mark Udall (D-CO) and others joining, announced today that they will introduce a stand-alone Renewable Electricity Standard (RES) bill. The bill will require sellers of electricity to obtain the following milestones in adding renewable energy resources or energy efficiency:
2012-2013 - 3%
2014-2015 - 6%
2017-2018 - 9%
2019-2020 - 12%
2021 - 2039 -15%
Renewable resources that can be used toward compliance will include wind, solar, ocean, geothermal, biomass, landfill gas, incremental hydropower, hydrokinetic, new hydropower at existing dams, and waste-to-energy. For utilities that are unable to meet their RES targets, the bill proposes to charge a compliance payment at a rate of 2.1 cents per kilowatt hour, with such amounts then being used for renewable energy development or to offset consumers' bills.
A first step, yes. But a small one.
Follow the link to learn more:
Xcel Energy is seeking to acquire up to 250 MW of new wind generation in the Upper Midwest in a Request for Proposals (RFP) announced today. Xcel will consider purchasing energy output from new wind projects through a power purchase agreement or owning the wind generation assets.
Xcel will accept proposals of any size so long as they will be ready to be placed in service by December 31, 2012, the current expiration date for the Federal Production Tax Credit. Xcel explained the timing and purpose of this request in the RFP and in its Application for Resource Plan Approval 2011-2015 (MPUC Docket E002/RP-10-825):
"Because the Federal Production Tax Credit ("PTC") is scheduled to expire at the end of 2012, we believe we should continue to explore acquisition of wind power to capture PTC savings for our customers. However, we do not need to add wind power to comply with RES/REO milestones in the next five years. Requesting proposals for additional wind generation prior to the expiration of the PTC provides us with an opportunity to achieve pricing that remains cost-effective for customers under a variety of future scenarios. If the results of our bidding program do not provide adequate benefits we have the option to defer acquisitions and still stay on track with compliance."
The RES/REO milestones are Minnesota's Renewable Energy Standard and Renewable Energy Objective, which ultimately require Xcel to have 30% renewable energy by 2020.
Proposals are due by October 15, 2010. The full RFP is available here.
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.
With a swift 13-page order today, FERC rejected Puget Sound Energy’s proposed wind integration rate, stating that the rate was not shown to be “just and reasonable” under section 205 of the Federal Power Act. “Changing system conditions, such as an increasing amount of wind generation described by Puget, present unique challenges that may require novel solutions. However, such solutions must fit the problems they are intended to solve, and the Commission must ensure that ratepayers are protected from rate proposals—such as the one proposed by Puget here—that are not shown to be related to the actual, demonstrable costs incurred in providing service.”
To determine the rate, Puget had used a proxy rate calculated using hypothetical capacity costs from a hypothetical generator. Puget chose its proxy from a group of five commercially available peaking units in the area. FERC stated that although it will allow for the recovery of legitimate and verifiable opportunity costs, Puget’s proposed rate was not a “reasonably accurate representation of the opportunity costs Puget incurs” in providing wind integration service. Because FERC cannot permit Puget to over-recover its costs in providing the service, the rate was rejected. Puget will undoubtedly be back to FERC with a rate that attempts to be consistent with FERC’s order.
Click here to read the order.
To follow up on my colleague Janet Jacobs' blog on this exciting topic, here's some more detailed information about the MOU, especially as it relates to marine and hydrokinetic ("MHK") technologies:
The United States Department of Energy’s Office of Energy Efficiency and Renewable Energy (“EERE”) and the United States Department of the Interior’s newly-renamed Bureau of Ocean Energy Management, Regulation, and Enforcement (“BOEMRE”) (see Note below) signed a Memorandum of Understanding for the Coordinated Deployment of Offshore Wind and Marine and Hydrokinetic Energy Technologies on the United States Outer Continental Shelf (the “MOU”).
The purpose of the document is to prioritize and facilitate environmentally-responsible deployment of commercial-scale offshore wind and MHK energy technologies on the Outer Continental Shelf (the “OCS”) through collaborative efforts. In a recent blog, I mentioned that the DOE has committed $15.36 million to help researchers and developers alike to bring various MHK technologies closer to commercial deployment. This MOU represents yet another effort to spur the growth of the burgeoning offshore renewable energy industry.
An interagency working group has been tasked with developing an action plan that addresses the deployment of offshore renewable energy projects, including both offshore wind and MHK technologies, within 30 days. The action plan will outline how the BOEMRE and EERE can work together to streamline leasing and regulatory processes on the OCS for those sites with high energy resource potential. The MOU also outlines how the agencies will share information and undertake collaborative activities such as stakeholder engagement, technical and environmental research, joint evaluation of standards and timelines for development, and the dissemination of information to decision makers.
Note: On June 21, 2010, DOI Secretary Ken Salazar issued Order 3302 renaming the Minerals Management Serivce the BOEMRE.
The DOE has issued a Request For Information ("RFI") to get the public's input on the development of a Wind Energy Workforce Roadmap, which will provide details on the current workforce landscape in the wind industry as well as future steps necessary to train and develop a green workforce for the sector. Ultimately, the Roadmap will help shape policy objectives and the overall development of a wind energy workforce.
Here is the link to the RFI: https://www.fedconnect.net/FedConnect/?doc=DE-FOA-0000392&agency=DOE
Yesterday DOE announced that up to $6 million to be awarded to one or two teams over two years to improve short-term wind energy forecasting, which will enhance the ability of utilities and electricity grid operators to forecast wind power generation.
One to two competitively-selected recipient team(s) will work with DOE and the National Oceanic and Atmospheric Administration (“NOAA”) to deploy atmospheric measurement systems, and demonstrate the value of these forecasting improvements for electric utility operations. The recipient team(s) will include wind plant operators, wind forecasting and meteorological services companies, electric utility system operators, and research organizations.
DOE will provide $3 million this year - $2 million to NOAA to fund its technical support of the selected projects and $1 million to the selected team. DOE also anticipates providing an additional $3 million in fiscal year 2011 to NOAA and the recipient team(s) to complete the project.
Go to the FedConnect Web site for additional details.
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 Wyoming Game and Fish Department ("WGFD") has extended the public comment period on a draft document: "Wind Energy Issues: Impacts and Mitigation for Wildlife in Wyoming" from December 18, 2009 to February 1, 2010. The document provides recommendations for assessing impacts to wildlife from wind energy projects, for collecting data, and for mitigating effects on wildlife. The WGFD is especially concerned about the potential impacts of wind energy on sage grouse, which are highly sensitive to disturbances and habitat modification. The adoption of the proposed recommendations could greatly impact the future siting and development of those wind energy projects in Wyoming that are required to obtain a permit from the Wyoming Industrial Siting Council. The Interwest Energy Alliance, a trade association focused on furthering renewable energy development in the intermountain region (Arizona, Colorado, Nevada, New Mexico, Utah and Wyoming), will be working with wind energy developers and concerned stakeholders in this matter, including the Wyoming Power Producers Coalition and Pacificorp, in preparing comments to the WGFD's recommendations. Parties interested in becoming a member of the Interwest Energy Alliance should contact Craig Cox, Executive Director, Interwest Energy Alliance, P.O. Box 272, Conifer, Colorado 80433, (303) 679-9331, firstname.lastname@example.org.
On November 18, 2009, the Wyoming interim Joint Revenue Committee (the "Committee") considered two bills, each of which proposed to tax wind generated electricity. Neither bill passed the committee on tie votes of 6-6 (4-4 House members and 2-2 senate members). One of the bills sponsored by Sen John Schiffer, R-Kaycee, chairman of the Committee (legisweb.state.wy.us/interimCommittee/2009/10LSO-0126w4.pdf) proposed a tax of $.0010 upon each kilowatt hour for electricity produced and sold in the State of Wyoming. An exemption was provided for electricity produced for the personal consumption of the producer. A power producer using coal or other fuels would break even on the generation tax through a credit equal to the severance tax portion of their electricity production costs. The proposed tax works out to be an approximately 5 percent tax on generation. The second bill considered by the Committee was sponsored by Rep. David Miller, R-Riverton, (legisweb.state.wy.us/interimCommittee/2009/10LSO-0062w2.pdf). Rep. Miller's bill was similar to Sen. Schiffer's bill, but would only provide the credit to traditional power producers if they agree to use 90 percent of the credit on electricity generation or transmission projects and put the other 10 percent into the state's low income energy assistance program. Proponents of the proposed tax cited a number of factors in favor of the bill including the fact that wind projects should contribute to state and local governments equally with other energy industries. For example, Wyoming imposes a severance tax on natural resources, which includes (approximately) a 6 percent tax for oil and gas and a 7 percent tax for coal. Opponents of the tax bills, including the group of wind energy developers represented by the Wyoming Power Producers Coalition, argued, among other things, that (i) wind energy projects already pay property taxes and provide other financial benefits to the local communities and (ii) the taxation issue should be studied carefully so as not to discourage wind energy development in Wyoming.
The taxation issues was studied at great length by the Wyoming Wind Energy Task Force (the "Task Force"), which issued its Final Report and Recommendations on November 1, 2009 (legisweb.state.wy.us/). The Task Force report indicated that the "industry leaders strongly encouraged a taxation policy which is based on an accurate and comprehensive understanding of the costs and burdens faced by the industry, as well as the direct and indirect benefits that will be realized by Wyoming from wind energy development." The Task Force went on to recommend the following with respect to taxation:
- that the Joint Revenue Committee comprehensively study the issues surrounding taxation of the wind energy industry;
- any proposed new tax be imposed in a way so as to encourage the diversification of Wyoming's economy and so as not to force the wind energy industry out of Wyoming;
- any tax should be designed to encourage the development of employment opportunities for Wyoming's people and to encourage the development of businesses ancillary to the wind energy industry;
- that the Legislature conduct a careful examination of all burdens placed on wind energy producers and weigh those burdens against any benefits the producers realize by harnessing Wyoming's high quality resources; and
- any tax burden proposed be calculated to maintain some competitive advantage for Wyoming's wind energy producers as they deliver electricity to distance markets where a demand for their product exists.
On a final note, although the proposed tax bills did not pass out of Committee, individual legislators can still attempt to gain introduction votes for such legislation during the February 2010 legislative session. However, since the 2010 legislative session is a budget session, introduction of such bills would require a two-thirds vote, which appears unlikely given the current economy. It is important to point out that the taxation debate in Wyoming (and perhaps other states) is a signal to wind energy developers that they may want to revisit or consider the "change of law" risk under a long term power purchase agreement and whether the levy of a generation tax could be passed on to the purchaser under those contracts.
Wisconsin Governor Jim Doyle has signed a bill into law that will require the state Public Service Commission (PSC) to promulgate rules establishing common standards for political subdivisions to regulate the construction and operation of wind energy systems. The legislation seeks to address the patchwork regulatory framework created by local jurisdictions' development of their own siting regulations, and to address the concerns of developers who have been hesitant to develop wind energy systems in the state.
Previously, a municipality was prohibited from placing any restriction on the installation of a wind energy system unless the restriction satisfies certain conditions, including protection of public health or safety. The new law allows limited and generally uniform regulation of wind energy systems, and specifies that a municipality (i) may not regulate wind energy systems unless it adopts an ordinance that is no more restrictive that the PSC rules, and (ii) may not impose any restriction on a wind energy system that is more restrictive than the PSC rules.
U.S. Representatives Collin Peterson (MN) and Tim Walz (MN) introduced the Wind Energy Promotion Act (WEPA) last month. If WEPA becomes federal law, the Renewable Energy Production Tax Credit (PTC) promises to become an even more potent driver for wind power project development. Under current law, the PTC may only be used to shelter passive activity income from tax liability.
If adopted, WEPA would allow the use of the PTC to shelter up to $40,000 of ordinary income, a modification that would boost the effectiveness of the PTC.
Click here to read the full analysis on WEPA and the opportunities this presents.
In a recent report published by Minnesota 2020, a non-partisan think tank focused on public policy matters including economic development, health care, education and transportation, the group notes that Minnesota needs an additional 4,000 MW of wind power to meet its Renewable Energy Standard, set at 25% by 2025. The think tank also notes that achieving the RES would "create up to 2,200 new jobs during the 17-year construction phase and more than 900 sustained jobs during the wind farms lifetime operations," which numbers may increase as Minnesota reaches beyond its minimum 25% requirement. The report also includes several short- and long-term recommendations to encourage the presence of wind energy companies in Minnesota, and thus the market (including training) for jobs within the wind industry as well.
About a month ago we issued an alert regarding a $45 million funding opportunity announcement ("FOA") for the development of a wind turbine drivetrain testing facility (alert available here).
Today, the Department of Energy ("DOE") announced that they are hosting a webinar regarding this FOA. The webinar will be held July 30, 2009 at 11:00 a.m. Eastern. Through this webinar, DOE will provide a brief overview of the FOA and will participate in a question and answer period. However, all questions must be submitted in advance (by July 27, 2009 at 2:00 p.m. Eastern) to windDynamometer@go.doe.gov
To attend this webinar, register in advance by clicking here.
On July 16, 2009, the Federal Energy Regulatory Commission (FERC) issued a Policy Statement on smart grid technologies, providing guidance on future smart grid interoperability standards and establishing an interim incentive rate policy that applies to near-term smart grid deployments (even those used in pilot or demonstration projects). Notably, FERC identified four technologies as being key to smart grid development: (1) digital devices and software that provide system operators with the near real-time ability to react to bulk power system conditions; (2) demand response; (3) electric storage devices, such as batteries and pumped storage, that will help integrate new resources into the grid; and (4) electric vehicles. FERC intends that these technologies will inform both the smart grid standards development process as well as the Department of Energy's release of stimulus funds available under the American Recovery and Reinvestment Act.
In addition, FERC established an interim rate policy that, once certain showings are made, will provide public utilities with the ability to recover the costs of FERC-jurisdictional smart grid technologies and the legacy systems being replaced. The interim rate policy also allows public utilities to apply accelerated depreciation to smart grid deployments and recover the full cost of smart grid technologies that are later abandoned or made obsolete. Public utilities seeking incentive rate treatment must file an appropriate application with FERC before it adopts smart grid interoperability standards.
For more information on FERC's Policy Statement, click here for our recently-released client alert.
If you would like to read the Policy Statement itself, click here.
Farmers, ranchers and rural business owners have until July 31, 2009 to apply for a Rural Energy for America Program ("REAP") grant from the USDA for the purchase and installation of small wind turbines. The grants provide up to 25% of the total installed cost of a small wind turbine system, and together with the Federal Investment Tax Credit ("ITC"), can cover up to 50% of the costs of the system for an eligible candidate. Additional funds may also be available from local utility cooperatives or rural electric associations which give rebates to their members.
Applications must be submitted to local USDA Rural Development offices by July 31, 2009. However, the application itself takes time to complete, and applicants should give themselves 2 weeks to fill it out.
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.
On July 2, 2009, the Department of Energy ("DOE") announced $59 million in conditional loan guarantees in the form of $16 million for a wind turbine assembly plant and $43 million for a 20 megawatt flywheel energy storage plant.
Nordic Windpower, USA has been conditionally offered a $16 million loan to support the tooling and commercial-scale set up of its assembly plant in Pocatello, Idaho. This assembly plant produces one megawatt two blade turbines which are 10% less costly to manufacture, install, operate, and maintain than competing systems.
Beacon Power was conditionally offered a $43 million loan to support the construction of a 20 megawatt flywheel energy storage plant in Stephentown, New York. The flywheel system is utilizing a newly developed technology to provide frequency regulation services by absorbing and discharging energy to maintain the consistency of power on the electric grid.
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
The U.S. Department of Energy Wind Powering America Program today announced that two Washington state public utility districts, Cowlitz County PUD and Klickitat PUD, are the co-winners of the 2009 Public Power Wind Pioneer Award for their outstanding teamwork and innovation in the development of the White Creek Wind Farm. The annual award was created in conjunction with American Public Power Association (APPA) and the Demonstration of Energy-Efficient Developments (DEED) Program to recognize pioneers in wind power.
A panel of wind, government, national laboratory, and public power experts from across the United States selected Cowlitz and Klickitat from sixteen public power utilities nominated for the award.
On June 2, 2009, the Department of Energy ("DOE") issued a Funding Opportunity Announcement ("FOA") providing $24 million for the development of consortia between universities and industry to focus on critical wind energy challenges.
DOE intends on awarding two to three grants of $8-12 million. The grants will be used to address two areas:
- Partnerships for Wind Research and Turbine Reliability. Universities in wind resource areas are encouraged to apply with industry partners to study major challenges facing today's wind industry. DOE is highly encouraging research in turbine reliability, but projects are eligible if they meet one or more challenges described in the 20% Wind Energy by 2030 report.
- Wind Energy Research & Development. Universities are encouraged to apply with industry partners for grants to fund R&D to advance material design, performance measurements, and analytical models related to wind energy development. The goals of this research shall be to improve power systems operations, wind turbine and/or component manufacturing, and interdisciplinary systems integration.
Applicants interested in either area must file a letter of intent by June 16, 2009 and FOA applications are due by July 29, 2009.
On June 19, 2009, DOE announced an extension to the deadline for submittal of a letter of intent for this program. Letters of intent must now be submitted by June 29, 2009. Applications are due on July 29, 2009.
As promised in a recent blog entry, we've issued a client alert providing a detailed analysis of the final Minerals Management Service (MMS) regulations governing leases for energy production on the Outer Continental Shelf (OCS), including wind and ocean energy. Please contact us with any questions!
On April 10, the Federal Energy Regulatory Commission approved a request for various transmission infrastructure investment incentives submitted by Green Power Express LP (GPE), a transmission-only partnership that proposes to build a 765 kV "green superhighway" consisting of three interconnected loops in North and South Dakota, Minnesota, and Iowa. GPE's proposal will also extend radially into Wisconsin, Illinois, and Indiana, making use of existing substations in some locations and constructing high voltage substations in others. In total, the project will include approximately 3,000 miles of transmission lines that reach 12,000 MW of wind and stored energy. GPE estimates the project's cost at $10-12 billion and hopes the project will be in service in 2020.
FERC's approved the following (non-exhaustive) key incentives that reduce GPE's exposure to risk in moving the project forward.
Abandoned Plant. FERC granted GPE's request to recover prudently incurred expenses if the project is abandoned for reasons outside of GPE's control. FERC stated that the recovery of abadonment costs is a means for encouraging transmission development, reducing the risk that GPE's investors may lose their entire investment.
Regulatory Asset. FERC will allow GPE to create initial and subsequent vintage regulatory assets in order to defer pre-construction, development, and start-up costs until GPE has customers from which it may later recover those costs. Such cost deferral will also help GPE attract financiers.
Construction Work in Progress. FERC approved GPE's request to include 100 percent of construction work in progress in its revenue requirement, allowing GPE to service its debt and reduce borrowing over the project's development--something that would otherwise be difficult for a $10-12 billion project with a 2020 in-service date.
The incentives granted to GPE, as well as other recent changes to FERC's transmission policies, show that the agency is becoming increasingly serious about spurring transmission development forward. If we are to reach the 62 GW of wind currently in the Midwest ISO interconnection queue, as well as other renewable resources elsewhere, transmission developers will need creative regulatory solutions to help attract financiers and gain firm commitments from generation developers. FERC continues to take positive steps forward.
Among all the interesting presentations at this month's AWEA transmission and wind workshop, American Superconductor's presentation about developments with superconducting transmission lines was particularly noteworthy. Superconducting direct current lines offer greater efficiency, as well as siting and aesthetics benefits, but have historically fallen victim to much higher costs when compared to traditional overhead transmission lines. However, with talks of extra-high voltage "green superhighways" transmitting renewable energy from the nation's interior to load zones, it appears from American Superconductor that the costs of a 5 GW, 200 kV superconductor line are nearly equivalent to 765 kV overhead lines when built on a 1,000 mile scale. Perhaps we will see a superconducting pipeline instead of an extra-high voltage overlay.
For more information about the viability of superconducting transmission lines, look for American Superconductor's White Paper in the near future.