FERC Initiates Proposed Rulemaking Affecting Interconnection Facilities

During today's open meeting, the Federal Energy Regulatory Commission (FERC) issued a proposed rulemaking that impacts the owners of gen-tie lines, particularly those owners who are developing multi-phase projects that require priority to interconnection capacity to support future phases.  The proposed rule would ease existing FERC policies that treated gen-tie lines just like any other transmission facility and required owners to make interconnection capacity available to third parties if the owner could not provide enough documentation proving its planned use of the gen-tie lines.

FERC has proposed the following:

  • Gen-tie line owners will be granted a blanket waiver from the requirement to (x) maintain a transmission tariff and OASIS and (y) comply with the standards of conduct.  FERC will revoke that blanket waiver only when it is in the public interest to do so, and not simply when a third party requests transmission service over a gen-tie line.
  • Third parties seeking to interconnect with existing gen-tie lines will be required to do so using the rules and regulations applicable to service requests under sections 210 and 211 of the Federal Power Act.
  • Gen-tie owners who are eligible for the blanket waiver from maintaining a tariff, etc., will be granted a 5-year safe harbor period giving the owner the benefit of a rebuttable presumption that (1) the owner has plans to use the gen-tie line's capacity, and (2) the owner should not be required to expand its facilities.  Third parties would have an opportunity to rebut that presumption, but those third parties would have the burden of proof.  FERC proposes that the 5-year period would begin on the gen-tie energization date.  Gen-tie owners would also be required to make an informational filing with FERC in order to take advantage of the safe harbor rights.
  • Lastly, FERC has asked whether the affiliates of public utility transmission provider should receive the benefit of the proposed rules.  

The proposed rulemaking is available here:  Gen-Tie Rulemaking

Comments are due by 60 days after publication of the proposed rule in the Federal Register.  Please let us know if you have questions about the proposed rulemaking and/or would like to submit comments to FERC.

 

The Price of Developing Power Projects in Kern County Just Went UP

The East Kern Wind Resource Area (EKWRA)--it's a mouthful--and it's also a hotbed for renewable energy development and the location of a fight over millions of dollars among Southern California Edison (SCE), the California ISO, and independent power developers (IPPs).  Late last week, the Federal Energy Regulatory Commission (FERC) scored that fight in favor of SCE and the California ISO.

For the past few years, SCE has been working to reconfigure the transmission system in the EKWRA region in order to address a reliability issue occurring there.  But the reconfiguration would have another impact--it would modify the transmission system in the area so that it became a distribution system under SCE, rather than CAISO, control.  To IPPs, that modification came with significant cost consequences:  in the interconnection process, IPPs funding network upgrades on the transmission system receive a full reimbursement for the cost of those upgrades; distribution upgrades, on the other hand, result in no reimbursement.  For IPPs who had assumed they would be reimbursed the network upgrade costs that appeared in their interconnection agreements (which often cost a single project millions of dollars), it came as something of a surprise when they learned that the reconfiguration might cause their reimbursements to dry up.

And so the IPPs challenged SCE and the California ISO.  In its decision, FERC determined that the reconfigured EKWRA facilities are distribution, or non-integrated facilities, and that the California ISO correctly transferred control over the facilities to SCE's tariff.  As a result, no further reimbursements to the IPPs will occur.  "Despite being informed of the possibility of reclassification, [the IPPs] made a business decision to proceed with interconnection."  For some IPPs, this could have a very costly impact.  

You can read the entire order here:  EKWRA Order.

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.   

 

 

Raising the Bar For Interconnection In the Southwest Power Pool

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.

Rate Schedules Galore! FERC's Decision in Chehalis Power Generating, LP

Interconnection customers:  be on notice.  Your interconnection agreement may not be just a transmission provider service agreement that allows your project to interconnect with the transmission system.  It may also be a rate schedule--your rate schedule--that you must file with FERC or suffer the consequences for violating the Federal Power Act.  

 

At last week's open meeting, FERC issued a decision in Chehalis Power Generating, LP where FERC recapped the longstanding requirement that public utilities must file the rates, terms, and conditions for the jurisdictional services they provide.  So far, so good.  But the Chehalis decision focuses on an interconnection customer who, for some time, provided uncompensated reactive power service under its interconnection agreement--a service that is provided by all interconnection customers who are required to operate their projects within a specified power factor range.  (If you're keeping track, that's everyone but wind projects.)  In fact, FERC's pro forma interconnection agreement even requires interconnection customers to operate their projects in this way in order to maintain reliability.  

 In Chehalis, FERC said the following:  "In order to clarify the Commission's policy related to reactive power service provided without compensation, the Commission finds that, on a prospective basis, for any jurisdictional reactive power service (including within dead-the-deadband reactive power service [i.e., the service that nearly all interconnection customers supply]) provided by both existing and new generators, the rates, terms, and conditions for such service must be pursuant to a rate schedule on file with the Commission, even though the rate schedule would provide no compensation for such service."  (brackets added)

In other words, interconnection customers who have not offered to provide any service but who instead operate their projects pursuant to the requirements that have been imposed by FERC, and who do so without compensation, must file their interconnection agreements as a rate schedule. But what regulatory purpose does this serve?    

As a result of the Chehalis decision, FERC will be holding a workshop to explore the mechanics of filing reactive power rate schedules for which there is no compensation.  At a minimum, I hope that FERC exempts all interconnection customers who provide uncompensated reactive power services from any filing requirement.  If not, FERC Staff will be very busy.

 

 

7th Circuit Affirms FERC's Decision on Multi-Value Projects, Relying Heavily on Policy of Promoting Wind Development

From my colleague, Andrew Moratzka:

On June 7th, 2013, the United States Court of Appeals for the Seventh Circuit issued an opinion in Illinois Commerce Commission, et al., v. Federal Energy Regulatory Commission, affirming the Federal Energy Regulatory Commission’s approval of the Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) tariff for financing new high-voltage power lines that largely serve remote wind farms.

 

Six issues were before the court: (i) the proportionality of benefits to costs for MVPs; (ii) the procedural adequacy of the previous proceedings; (iii) the propriety of an energy-cost allocator for MVPs; (iv) whether MISO should be allowed to add an MVP fee to utilities belonging to the PJM Interconnection, LLC (“PJM”); (v) whether MISO should be permitted to assess some costs associated with MVPs; and (vi) whether the Commission’s approval of the MVP tariff violates the Tenth Amendment to the Constitution by invading state rights. The fourth and fifth issues were remanded. And the court quickly dismissed the sixth issue at the outset of the opinion, stating that the arguments amounted to an assertion that the MVP tariff “provides a carrot that states won’t be able to resist eating.” This entry therefore focuses on issues (i) – (iii).

 

The court addressed issues (i) and (ii) together. There are two important takeaways in this section of the opinion. First, MISO’s burden of establishing rough proportionality of costs to benefits under the Federal Power Act arguably changed in the name of policy. The court stated that “The promotion of wind power by the MVP program deserves emphasis” and that wind power will probably “grow fast and confer substantial benefits on the region.” The court determined there was “no reason to think these benefits will be denied to particular subregions of MISO” and found that other benefits (e.g., reliability) were real, even though they couldn’t be calculated in advance.   The court then went on to find that MISO’s and FERC’s efforts to match cost and benefits, even if crude, were sufficient. It is not entirely clear how this aspect of the opinion can be reconciled with the court’s previous opinion in Illinois Commerce Commission v. FERC. But it appears the policy of promoting wind power influenced the decision in this case. Moreover, the court rejected requests for an evidentiary hearing on this issue, on the basis that requiring such proceedings after two years of appeal “would create unconscionable regulatory delay.” 

 

The second takeaway is a comment made by the court in response to a criticism raised by the State of Michigan, which claimed it would not benefit from out-of-state MVPs because a provision in Michigan law forbids Michigan utilities from counting renewable energy generated out of the state to satisfy requirements under the state’s Clean, Renewable, and Efficiency Act of 2008. The court stated that Michigan cannot discriminate against out-of-state renewable energy without violating the commerce clause of Article I of the Constitution. This statement could have significant ripple effects on similar laws around the country that give preference to in-state renewable resources or impose limits on imported generation.

 

The policy of promoting wind development also seemed to influence issue (iii). The court found that the objection to an energy allocator was refuted by the fact that a primary goal of the MVPs is to increase the supply of renewable energy. It acknowledged that wind production is intermittent and not a reliable source of energy to meet peak demand. But the court concluded that MVP lines will enable plants to serve off-peak demand and stated that “MISO and FERC were entitled to conclude that the benefits of more and cheaper wind power predominate over the benefits of greater reliability brought about by improvement in meeting peak demand.” 

A Big Day at the FERC Open Meeting

 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

FERC Conditionally Approves MISO Queue Reform

On Friday, March 30, 2012, the Federal Energy Regulatory Commission (the "Commission") conditionally approved a proposal from the Midwest Independent System Operator ("MISO") to change its generator interconnection queue procedures to address backlogs and late-state terminations of generation interconnection queue agreements (FERC Docket No. ER12-309-000).  The new procedures are effective January 1, 2012.  The reforms approved on Friday are MISO's third set of significant queue reforms since 2008 as MISO has continued to shift its procedures for processing interconnection applications from a "first-come, first-served" approach to a "first-ready, first-served" approach.  

For developers, the most critical changes are the new cash-at-risk milestones required for projects to enter the Definitive Planning Phase and after execution of a Generator Interconnection Agreement ("GIA").  The purpose of these new milestones is to require interconnection customers to put more money at risk earlier in the process so that projects that advance through MISO's queue to the Definitive Planning Phase will be more likely to reach commercial operation.  Other important changes include revised timelines, new study procedures, and Net Zero Interconnection Service.

Click here to continue reading this alert.

BPA Submits Compliance Filing in FERC Environmental Redispatch Proceeding

The Bonneville Power Administration (BPA) is gearing up for spring with its revised Oversupply Management Protocol (OMP), submitted last week as a compliance filing in the Federal Energy Regulatory Commission (FERC) proceeding on BPA’s “Environmental Redispatch” policy. BPA’s compliance filing was submitted in response to FERC’s December 7, 2011 order holding that BPA’s Environmental Redispatch policy of curtailing wind generation without compensation during periods of high water was unduly discriminatory and preferential. FERC directed BPA to file a revised Open Access Transmission Tariff (OATT) addressing the comparability concerns raised in the proceeding.  

Under the OMP, BPA would curtail wind generation during periods of high water in order to deliver federal hydropower in place of the curtailed generation, but would provide “compensation” for the curtailments based on the wind generators’ submitted displacement costs. The “compensation” would come in part from the wind generators themselves, who would be allocated a portion of the displacement costs through a new rate.   

 

BPA’s compliance filing is conceptually similar to the draft OMP it circulated for comment in February, although there are some changes of note. First, the OMP will now be in place for only one year, instead of the original 2015 end date. Second, wind generation with power sales contracts signed after March 6, 2012 will be compensated differently than wind generation with power sales contracts signed before then. Though both will receive compensation for lost production tax credits and lost renewable energy credits, the level of compensation for wind generation with post-March 6 contracts is not entirely clear. Third, wind generators can opt out of receiving compensation in exchange for not being allocated a share of the displacement costs; however, those opting out will be given a displacement cost of $0/MWh and thus be the first wind generators curtailed. Fourth, instead of submitting displacement costs to BPA, generators must now submit their displacement costs to a third-party evaluator.  BPA will no longer impose a penalty for inaccurate costs, but may ask FERC to investigate inaccuracies (or perceived inaccuracies) in the displacement cost submissions. 

 

FERC is accepting comments on BPA’s compliance filing through 5 pm EST Tuesday, March 27, 2012. In addition, BPA is seeking comments on its OMP Business Practice, which contains information on how BPA plans to implement the OMP. Comments on the OMP Business Practice are due by close of business on Monday, March 26, 2012. 

BPA Seeks Comment on Draft Proposal to Split Environmental Redispatch Costs

The Bonneville Power Administration (“BPA”) made headlines this week with the release of its Draft Oversupply Management Protocol (the “Draft Oversupply Protocol”). BPA’s Draft Oversupply Protocol is intended to address concerns raised by BPA’s Environmental Redispatch (“ER”) policy of curtailing wind generation without compensation during periods of high water. Back in December, in response to a complaint filed against BPA by a group of owners of Pacific Northwest wind energy projects, the Federal Energy Regulatory Commission (“FERC”) issued an order holding that BPA’s ER policy was unduly discriminatory and preferential, in violation of Section 211A of the Federal Power Act (the “ER Order”). FERC directed BPA to file a revised Open Access Transmission Tariff (“OATT”) by March 6, 2012 addressing the comparability concerns raised in the proceeding in a manner that would provide for transmission service that is not unduly discriminatory or preferential. Click here to read our Energy Law Alert on the ER Order

BPA and several other parties filed requests for rehearing of the ER Order. FERC’s procedural rules provide that if FERC does not act on a rehearing request within 30 days of the filing, the request for rehearing is deemed denied. Earlier this week, FERC issued an order (the “Rehearing Order”) granting rehearing in order to give itself more time to consider the matters raised in the requests for rehearing.  Notwithstanding the Rehearing Order, BPA must still submit its compliance filing on the initial ER Order no later than March 6.

 

In preparation for its March 6 compliance filing, BPA released for comment its Draft Oversupply Protocol.  In a nutshell, BPA proposes to provide approximately 50 percent compensation to operating wind generators in order to continue its ER policy of (i) curtailing wind generators during periods of high water, and (ii) using the wind generators’ reserved transmission capacity to deliver federal hydropower.

 

Under BPA’s Draft Oversupply Protocol, BPA would compensate wind generators for the costs of displacing wind curtailed during ER events. The displacement costs include the production tax credits and renewable energy credits the generators would have earned had their generation not been curtailed. However, for wind projects that reach commercial operation before March 6, 2012, approximately 50 percent of the displacement costs would be recovered from the wind generators through a new rate. BPA would allocate the other 50 percent of the costs to the users of the Federal Base System. Wind generators with a commercial operation date after March 6, 2012 have the choice of (i) avoiding the new rate by being redispatched without compensation or (ii) receiving partial compensation for the ER curtailments and sharing in the costs.  BPA proposes to conduct a rate case to determine how it will recover the displacement costs (i.e. what percentage of the costs it will collect from the wind generators and what percentage of the costs it will collect from users of the Federal Base System).

 

BPA is accepting comments on the proposal until noon on February 21, and will host a workshop on the proposal on February 14, from 9 am to noon. Click here for information on the workshop and how to submit comments.  

CUB Policy Center and UO Hold Inaugural Smart Grid Conference in Portland

The CUB Policy Center, in partnership with the University of Oregon School of Law,  will be holding its inaugural policy conference: Smart Grid: Today's Regulation and Tomorrow's Technology, on Friday, October 21, 2011, at the University of Oregon White Stag Block (70 NW Couch St., Portland, OR 97209).  The luncheon keynote speaker will be former FERC Commissioner Nora Mead Brownell, who is the co-founder of ESPY Energy Solutions.

The conference is designed to educate utility analysts, policy analysts, attorneys, industry professionals, stakeholders and others on the current regulatory environment in Oregon and the region and to provide a forum for investigating the opportunities and challenges of integrating the Smart Grid into that environment. The CUB Policy Center notes that space for this conference, which promises to be well attended, is limited and encourages attendees to register early.   

I'll be participating in the Closing Panel to recap and discuss lessons learned during the day, and I hope to see you there.

Puget Sound Energy Files for WUTC Review of "All-Source" RFP

Puget Sound Energy (PSE) has filed with the Washington Utilities and Transportation Commission (WUTC) a Request for Proposals for All Generation Sources (the all-source RFP) and a Request for Proposals for Electric and Demand Side Resources (energy-efficiency RFP). PSE filed the draft all source RFP on August 1, 2011 and plans to issue a separate energy efficiency RFP later.  

Under the all source RFP, PSE is seeking proposals for energy generation resources as capacity generation resources, as well as transmission products from BPA’s system to PSE's system. PSE is willing to consider both existing generation resources and resources that are under development but expected to achieve commercial operation no later than December 2015. According to PSE, a revised assessment of its portfolio needs and peak customer power requirements demonstrates a need for approximately 500 MW of capacity by the end of 2012.  PSE would be willing to consider various commercial arrangements under the RFP, including power purchase agreements, temporal exchange agreements, ownership arrangements (e.g., a transfer of development assets, a build-transfer arrangement, or sale of an existing asset), as well as transmission-only products from BPA’s system.

 

PSE will be hosting an RFP Proposal Conference on August 16, 2011, in Bellevue, Washington, to discuss the all-source RFP. To register for the conference, email janice.brown@pse.com. Public comments on the draft RFP are due on September 2, 2011, and PSE expects to receive WUTC approval by September 28. If the schedule holds, PSE plans to issue the final RFP solicitation on October 5, 2011.  PSE expects to select a final short list and notify respondents in 1Q 2012.

PSE’s web page for the RFP (including its proposed schedule and the draft RFP itself) can be found here.

FERC Issues Order No. 1000 on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities

Yesterday, the Federal Energy Regulatory Commission ("FERC" or "the Commission") issued Order No. 1000 in Docket No. RM10-23-000, a rulemaking proceeding initiated by the Commission on June 17, 2010.  Order No. 1000 is a Final Rule that weighs in at a whopping 620 pages and reforms the Commission's electric transmission planning and cost allocation requirements for public utility transmission providers. 

The order takes effect 60 days from its publication in the Federal Register and public utility transmission providers are required to make a compliance filing within 12 months of the effective date of the Final Rule.  Compliance filings for interregional transmission coordination and cost allocation mandated by the Final Rule must be submitted within 18 months of the effective date.

Attorneys here at Stoel Rives are reviewing the order and its implications for our clients now, but given the size and scope of the order, this blog will rely on summary information published by the Commission concurrently with the order to provide readers a general idea of its contents.

Continue Reading...

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.

Coming Very Soon: CPUC Energy Storage Workshop

On Tuesday, June 28, 2011, the CPUC will hold an “Electric Energy Storage Workshop” as part of its R10-12-007 proceeding for AB 2514, which defines the process by which the CPUC will consider electric energy storage standards for California’s investor owned utilities. The workshop will be held at in the Golden Gate Room at CPUC’s headquarters from 9:30 am to 4:00 pm.

According to a draft agenda circulated by the CPUC, the theme of the workshop will be addressing barriers to entry facing Electric Energy Storage (EES). The workshops goals are to identify actions that the CPUC should consider, as well as whether and how it should participate in other forums.

The morning will feature presentations from several different perspectives, with each presentation to be followed by Q&A:

 

  • Presentation from UC Berkeley and California Energy Commission (CEC) team on “2020 Vision Project”
  •  

  • Presentation from CAISO about recent storage-related activities at the Independent System Operator, including findings from recent studies.
  •  

  • Presentation from Southern California Edison (SCE) discussing a white paper entitled Moving Energy Storage from Concept to Reality.
  •  

  • Presentation from California Energy Storage Alliance about developer’s perspectives

The afternoon will feature a facilitated presentation about a staff straw proposal concerning potential CPUC actions. The CPUC will allow parties to provide post-workshop comments on both the presentations and the staff straw proposal.

The CPUC is willing to accommodate short presentations (five minutes or less) or share prepared material pertinent to the workshop. Any party who wishes to do so may contact Michael Colvin at michael.colvin@cpuc.ca.gov. For reference (or inspiration), a series of energy storage presentations made to the CPUC as part of its 2011 IEPR process can be found here.

Stoel Rives attorneys Seth Hilton and Janet Jacobs will be attending the workshop.

FERC Seeks Comments on Ancillary Markets and Energy Storage

On June 16, 2011, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) seeking comments on what it described as two separate but related issues, both of which apply to electric energy storage (EES). 

First, because FERC is interested in facilitating the development of robust competitive markets to provide ancillary services from all resources types, it seeks comment on “existing restrictions on third-party provision of ancillary services, irrespective of the technologies used for such provision.” In soliciting these comments, FERC noted the growing interest in rate flexibility among sellers of ancillary services, and a desire from those obligated to purchase those services to increase the available supply. Although a variety of resources can provide ancillary services, FERC believes that many are discouraged from doing so by the Commission’s restrictions on market-based pricing coupled with a lack of access to information that could help satisfy the requirements of those policies. Access to information is particularly difficult outside of areas served by RTOs/ISOs, which areas are often with the greatest need for an ancillary services market.

 

FERC pointedly invites comments on whether it should revise or replace the restriction set forth in Avista Corp., 87 FERC ¶ 61,223, order on reh’g, 89 FERC ¶ 61,136 (1999), which prohibits, absent a study showing lack of market power, third-party market-based sales of ancillary services to transmission providers seeking to meet their ancillary services obligations under the Open Access Transmission Tariff (OATT). Assuming that FERC revises or replaces the Avista restriction to facilitate the provision of ancillary services, it also seeks input on how it should contemporaneously ensure just and reasonable rates. In a related inquiry, the Commission is seeking comments on whether the various cost-based compensation methods for frequency regulation that exist in regions outside of organized markets can be adjusted to address the speed and accuracy issues identified in FERC’s recent Frequency Regulation Notice of Proposed Rulemaking for organized wholesale energy markets. See Frequency Regulation Compensation in the Organized Wholesale Power Markets, 76 FR 11177 (March 1, 2011), Notice of Proposed Rulemaking, FERC States & Regs ¶ 32,672 (2011). The June 16 NOI, when considered in context with this year’s NOPR on Frequency Regulation and last year’s NOI on EES, could signal that a broader rulemaking regarding EES is on the horizon.

 

Recognizing that “the role of electric storage and other new market entrants play in competitive markets is still evolving,” the Commission seeks comments on whether it should revise “current accounting and reporting requirements as they pertain to the oversight of jurisdictional entities using electric storage technologies” other than pumped storage hydro (for which FERC has established methods of accounting, reporting and rate recovery). Current utility accounting requirements do not appropriately fit EES due to the technology’s abilities to act like generation, transmission, and distribution assets. Accordingly, FERC is soliciting “specific details regarding whether and, if so, how to amend the current accounting and reporting requirements to specifically account for and report energy storage operations and activities.”

 

The NOI was published in the Federal Register on June 22, 2011, and comments are due sixty (60) days from that date.

 

Thanks to my colleague Jason Johns for his comments on this posting!

MATL Dispute Headed Back to District Court

The Montana Supreme Court has reversed a December 2010 district court decision that found that the developers of the Montana-Alberta Tie Line merchant transmission project do not possess eminent domain authority under Montana law and therefore could not take private land from a nonconsenting landowner.  In its reversal, the state Supreme Court cited House Bill 198 that passed during the 2011 Montana legislative session, which bill grants eminent domain authority to any person issued a certificate under the state's Major Facility Siting Act.  The Supreme Court noted that because the legislation applies retroactively to persons issued a certificate after September 30, 2008, and the MATL developers received their certificate on October 22, 2008, HB 198 now expressly provides eminent authority to MATL's developers.  The district court must now reconsider its earlier decision in light of HB 198.

On a related note, Concerned Citizens Montana is driving a citizens' referendum to repeal HB 198.  If the petition receives enough signatures, Montana voters will decide HB 198's fate in 2012.

Stoel Rives Energy Regulation Report

FERC Clarifies Qualifying Facility Restrictions in Sale/Resale Transactions

On May 19, the Federal Energy Regulatory Commission ("FERC") issued an order in Idaho Wind Partners I, LLC, a docket in which wind farm owners in Idaho petitioned FERC for approval of a unique transaction that would both provide eligible Renewable Energy Credits ("RECs") to a utility in California and leave the wind farm owners in a position to make a Qualifying Facility ("QF") "put" sale at avoided cost rates on the interconnecting utility.

FERC confirmed that so long as the third party is a QF, the size, affiliation, or relative physical location of the third party has no effect on the QF status of the power being sold and repurchased. Consequently, any power that the Idaho wind farms sell to a QF and then buy back may subsequently be sold to an electric utility at avoided cost rates.

Read more on the Qualifying Facility Restrictions

SunZia Transmission Obtains Approval of Ownership Structure, Anchor Tenant Proposal

On May 20, FERC granted SunZia Transmission's ("SunZia") petition for FERC's approval of the ownership structure and transmission service plans for the SunZia Southwest Transmission Project (the "Project"). SunZia had requested that each of its investor-owners be allocated ownership rights representing 100 percent of its respective pro rata investment in the Project, and that certain of the investor-owners be able to allocate up to 50 percent of their pro rata shares of transmission capacity to anchor tenants through long-term negotiated transmission contracts. In May 2010, FERC rejected SunZia's request to allocate 100 percent of the Project's transmission capacity (as opposed to ownership rights) among the owners according to their pro rata investment in the Project's capacity and ruled that the owners do not have exclusive rights to the Project's capacity equal to their share of investment in the Project.

Read more on the Approval of SunZia Ownership Structure and Anchor Tenant Proposal

Midwest ISO Releases Group 5 Re-Study System Impact Study

On May 19, the Midwest ISO released the long-anticipated Minnesota Group 5 Re-Study Generator Interconnection System Impact Study, which Re-Study was ordered by FERC as the result of a cost allocation dispute between a wind developer (Community Wind) and the Midwest ISO with respect to the Brookings County-Twin Cities transmission line.

Read more on Midwest ISO's Group 5 Re-Study Generator Interconnection System Impact Study

A Big Day for Transmission Rate Incentives: Multiple Applications Approved, and FERC Seeks Comments on Its Policies

FERC's May 19 open meeting turned out to be positive for transmission developers, as FERC approved transmission rate incentives (or related settlements) for five transmission projects located from the Atlantic coast to the desert Southwest. FERC also issued a Notice of Inquiry on its implementation of Section 219 of the Federal Power Act, and is seeking comments on how it should modify its policies and regulations to promote increased transmission investment.

Read more on each of FERC's Approved Transmission Rate Incentives

CEC Holds Workshop on Energy Storage for 2011 IEPR

The 2011 IEPR Committee Workshop on Energy Storage for Renewable Integration was held Thursday, April 28th at the California Energy Commission (CEC) offices in Sacramento.  The Workshop was presented in a three panel format, with each panel addressing specific topics, including (1) the need for energy storage in light of California’s renewable portfolio standard, greenhouse gas goals, smart grid and demand response, (2) the costs, benefits and revenues from energy storage applications, and (3) utility perspectives on energy storage. The full agenda, which describes the topics and the questions addressed at the Workshop, can be found here.

The CEC is not planning any further workshops on energy storage, but it will be making recommendations about the topic in its 2011 Integrated Energy Policy Report (IEPR). We understand that the CEC is seeking input on energy storage from all arenas, including developers and owners of gas-fired peaker plants.  Among other things, the CEC wants to understand the economic and environmental benefits and impacts of peakers (i.e., facilities that have the ability to ramp up in ten minutes, generate for a full hour, then be taken off line) compared to the cost and benefits of various energy storage technologies.  The CEC will use the information it gathers to determine if it makes sense economically to recommend a lower or a higher target for energy storage in its 2011 IEPR. 

 

 

The CEC’s report will be taken into account by the California Public Utility Commission (CPUC), which is conducting a separate proceeding under AB 2514 to determine appropriate energy storage targets for California’s investor-owned utilities. You can find our previous descriptions of the AB 2514 process here , here and here.  A report on last year's CPUC staff whitepaper describing energy storage technologies and their potential use in the California market can be found here

 

Parties who want to weigh in on energy storage in California must submit their comments to the CEC by 5 p.m. on May 16, 2011.   The comments must include the docket number “11-IEP-1N” and indicate “Energy Storage for Renewable Integration” in the subject line or first paragraph of the comments.  All filings in the IEPR proceeding are now accomplished electronically and can be submitted in either Microsoft Word format or as a PDF by e-mail to docket@energy.state.ca.us

 

Thanks to Kimberly Hellwig in our Sacramento office for her help in preparing this Blog!

 

California Public Utilities Commission Holds Prehearing Conference on Energy Storage Procurement Targets

As we’ve previously discussed, California’s AB 2514 requires the CPUC and municipal utilities in California to open proceedings by March 1, 2012 to determine appropriate targets, if any, for the procurement of viable and cost-effective energy storage systems by load-serving entities. Over a year before that deadline, the CPUC opened Rulemaking 10-12-007 in December of last year to both implement AB 2514 and “on [the CPUC’s] own motion to initiate policy for California utilities to consider the procurement of viable and cost effective storage systems.” In early March, the CPUC held an initial workshop on the scope of the rulemaking proceeding.

On April 21, the Commission held a prehearing conference to determine the scope and schedule for the proceeding. Stoel Rives partner Seth Hilton attended the conference. Among the issues discussed at the prehearing conference, led by Administrative Law Judge Yip-Kikugawa, was whether to conduct the proceeding in phases (e.g., first examining how storage might be applied, and then in a subsequent proceeding setting what the mandate will be for storage procurement), the issues to be covered in each phase , and whether evidentiary hearings would be necessary. 

According to ALJ Yip-Kikugawa, a scoping memo should issue in the next two to three weeks. The scoping memo will set out the issues to be considered in the proceeding and a schedule for their resolution. 

We'll be posting further information on Renewable + Law Blog when the scoping memo comes out, so stay tuned for further developments.

LexisNexis Selects Renewable + Law Blog to its Top 50 Environmental Law Blogs List

Having first reported to our readers in February that LexisNexis had nominated the Stoel Rives Renewable + Law Blog for its Top 50 Environmental Law & Climate Change Blogs for 2011 award, we are pleased to announce we made the list of winners! In publishing its Top 50 list, LexisNexis declared that our Renewable + Law bloggers’ “avowed passion for solar energy, wind energy, biofuels, ocean and hydrokinetic energy, biomass, waste-to-energy, geothermal and other clean technologies is evident in the care they take with this blog-the posts are frequent, the topics are interesting and cutting edge, and the writing is top notch.”

 

Thanks again to all our readers who make regular use of Renewable + Law Blog and those who wrote in to support us for this award. We're honored and inspired, and we plan to keep those Blogs and letters coming.

 

RFI for Substation-Size Li-ion Energy Storage System Demonstration Project

Electric Power Research Institute (EPRI) and Technology Transition Corporation recently issued a request for information (RFI) to prepare for multiple demonstrations and the market introduction of 1MW / 2MWh lithium ion battery energy storage systems (ESS) for electric utility grid management solutions.  EPRI and TTC have assembled a utility team for this project, and they encourage manufacturers of Li-ion systems and energy storage system integrators to respond to the RFI. The utility team will evaluate the responses to determine which ESS suppliers should be invited to a 2-day utility-manufacturer workshop to be held in June 2011 to discuss the project’s technical specification and demonstration plans.  The responses to the RFI will also influence the forthcoming Request for Proposals and the technical specification for approximately three demonstrations scheduled for 2012.

To be considered for participation in the proposed ESS project, including receipt of the resulting RFP in Q3 2011, responses must be received electronically, by 8 pm (20:00) Eastern Time, Monday, May 2, at storagespec@ttcorp.com.  A detailed description of the RFI process and the RFI response form can be found on the Technology Transition Corporation's website, here

Thanks to Emanuel Wagner, Project Coordinator for TTC, for bringing this RFI to my attention.  According to Emanuel, this would be the first Li-ion storage project of this size in the US, if not the world.  

Petition for Review Filed in TXU v. FPL Curtailment Case

On April 11, 2011, FPL Energy, LLC, et al., filed with the Texas Supreme Court a petition for review of the Texas Court of Appeals’ decision FPL Energy, LLC, v. TXU Portfolio Management Company, L.P. The case illustrates the significant economic impact that curtailment can have on variable energy resources. For a detailed description of the case and its implications, see our Renewable + Law Blog entry on the Court of Appeals’ decision here.

The petition for review focuses on the question of whether the Court of Appeals was correct in enforcing the liquidated damages provisions contained in three wind energy power purchase agreements. The pertinent provisions in each PPA required the petitioners to pay $50 for every MWh that the plants fell short of achieving the their minimum REC output guarantees—the Court of Appeals’ holding meant that the petitioners owed TXU roughly $29 million in shortfall damages for a four year period of curtailment imposed by the transmission provider (ERCOT), on top of the pain of losing the contract price and the production tax credit on each MWh of energy curtailed.

Continue Reading...

A Unique RFP for Energy Storage

Santa Fe-based Chamisa Energy Corporation recently announced a request for proposals for up to 250MW of nameplate wind generation resources to be used to provide energy to a 135 MW or larger compressed air energy storage (CAES) facility under development in Swisher County in the Texas panhandle.  The proposed CAES facility would compress air and store it in solution-mined underground caverns.  To convert the stored potential energy back into electricity, the stored air would be released and mixed with a small amount of natural gas to drive a turbine.  The RFP describes CAES as a "bulk electric storage technology used to complement wind energy generation so that wind energy becomes a fully dispatchable resource suitable for peaking, intermediate, baseload or tolling resource." 

The energy would be provided to the facility pursuant to a power purchase agreement (PPA).  Chamisa invites wind plants located either in the Southwest Power Power (SPP) or the Electric Reliability Council of Texas (ERCOT) to respond. Chamisa will consider proposals that supply wind energy for seven years, but prefers a minimum term of 15 years.  The target date for delivering electricity to the Storage Facility is the second quarter of 2014. 

Chamisa notes that it is not aware of completed or pending PPAs between WGR and CAES facilities, and thus anticipates that the successful proposal "will be creative in its approach to the RFP."  Although the RFP isn't explicit on the point, Chamisa's plan may be to purchase energy from a wind generator or wind generators pursuant to the PPA, store the energy, and then sell the electricity and ancillary services from the facility to a third-party off-taker.  If Chamisa can take the bulk of the energy into CAES primarily in off peak hours and then sell the stored energy during on-peak hours, might in theory be able to profit on the arbitrage between the two price points, although past efforts to get grid-scale storage to pencil out on that basis have had limited success.  Alternatively, the facility may be able to profit by using the stored energy to provide ancillary services, grid congestion relief, grid stability and support for grid expansion.

In principle, the CAES facility could also be used in a tolling arrangement by which a utility or a seller of wind energy hires the CAES facility for storage, pays a reservation and storage charge to Chamisa, and then dispatches the stored energy at will--in other words, the third-party offtaker could be the same party as the generator delivering the wind energy to the facility (e.g., a utility that is buying wind energy that it wants to shift from off-peak hours to on-peak hours).  Under this structure, the party tolling electricity would retain title to the electicity being stored and could arbitrage or otherwise deploy the stored energy into the market as it saw fit.  However, a tolling transaction of that type isn't clearly called for by the RFP (although it doesn't appear to be precluded).

Regardless, Chamisa's RFP will be worth monitoring to see whether an independent storage developer can create a workable market structure for its storage assets in order to facilitate financing.  The outcome of this effort will be of great interest to developers of solar and wind resources, as well as to developers of pumped storage and other grid-scale storage solutions.

The deadline for written or email questions is March 31, 2011, and proposals are due no later than 5pm Mountain Standard Time on May 16, 2011.  If submitted by mail, proposal(s) must be postmarked May 16th.  E-mail submission is preferred.  You can access Chamisa's RFP by clicking here.

 

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.

 

Continue Reading...

Parties convene in Portland to discuss the creation of an Energy Imbalance Market

A group of western utility executives, transmission officials, and regulatory analysts are convening in Portland, Oregon next week to discuss the creation of a western Energy Imbalance Market (“EIM”).  The EIM is part of an Efficient Dispatch Toolkit (“EDT”) proposed by a WECC subcommittee and the Western Interstate Energy Board (“WIEB”) that would include: (1) the EIM to supply energy imbalance service and congestion management, and (2) an Enhanced Curtailment Calculator (“ECC”) to manage power flow impacts across Balancing Authority (“BA”) seams.  As a point of reference, the Southwestern Power Pool launched a similar “Energy Imbalance Service” in 2007.

 

Why:  Renewable energy capacity in the West is expected to grow from roughly 13,000 MW today to 70,000 MW by 2020 as the result of state renewable energy requirements.  Current energy balancing practices are insufficient to meet the challenges of the anticipated variable generation increases in the Western Interconnection, according to a white paper prepared by WIEB staff.  Current bilateral transmission and scheduling practices do not, for instance, make use of remote balancing resources in the Western Interconnection and the EIM could help make more efficient use of generating resources located throughout its footprint.

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DOE Approves Loan Guarantee for ON Line

On October 20, my colleague Janet Jacobs reported that the U.S. Department of Energy ("DOE") had offered a conditional commitment of $350 million to NV Energy, Inc. and Great Basin Transmission South, LLC, an affiliate of LS Power Group, for development of the 500-kV One Nevada Transmission Line (the "ON Line project").

Well, good news.

Two days ago, Secretary Chu announced that DOE had approved a $343 million loan guarantee for the ON Line project- the first of its kind for a transmission line.  The ON Line project will stretch 235 miles from Ely, Nevada to a substation just north of Las Vegas at a projected cost of $500 million.  As the first phase of a larger transmission infrastructure project, the ON Line will initially be able to transmit approximately 600 MW of otherwise landlocked renewable energy to load centers.  When the final phase of the project is completed, the line will be able to transmit approximately 2 GW (or 2,000 MW) of renewable electricity from Idaho, Wyoming, and Nevada to serve customers in southern Nevada, California, and the rest of the Southwest.

FERC Finds an Interconnection Facility Requires an OATT

Update by  Sara Bergan and Jason Johns

The Federal Energy Regulatory Commission (FERC) recently issued an order rejecting a Common Facilities Agreement (CFA) under section 205 of the Federal Power Act (FPA) and related request for waiver from open access requirements. The CFA between Sky River and Windstar Energy involved a 9-mile, 230 kV generator tie-line in California known as the Wilderness Line. Sky River owns and operates a 77 MW wind facility and has an interest in the Wilderness Line along with several other Qualifying Facilities (QFs).

Windstar is developing a 60 MW wind facility for which it already has a generator interconnection agreement with SoCal Edison and the California ISO. Sky River entered into the CFA with Windstar to license a portion of Sky River’s interest in the Wilderness Line to enable the output from Windstar’s wind facility to reach the point of interconnection with SoCal Edison.  In other words, the CFA served to support Windstar’s interconnection with SoCal Edison. Sky River sought approval of the CFA and the open access waivers on the basis that the gen-tie line is not an integrated component of the grid and was designed solely as an interconnection line.

FERC did not accept the CFA or the waiver from the open access transmission tariff (OATT) filing requirement. FERC determined that the CFA was an “attempt to govern transmission service for an unaffiliated third party over the Wilderness Line outside the context of an OATT, with all its attendant rights and obligations.” Further FERC noted that waiver of obligation to file an OATT applies only until such time as a request for transmission service is made and that any transmission over the Wilderness Line for non-owners must be made pursuant to an OATT.

Ninth Circuit Decision Further Dismantles an Already Weakened Federal Transmission Siting Authority

Congress’ experiment with establishing federal siting authority for transmission lines suffered another setback after a Ninth Circuit Court of Appeals decision issued yesterday, February 1, 2011, vacated the Department of Energy’s (“DOE”) 2007 Transmission Congestion Study that had designated national interest electric transmission corridors in mid-Atlantic and Southwestern states. This ruling is the latest of three court and agency decisions that have limited or undermined the federal siting authority established at Federal Power Act section 216 by the Energy Policy Act of 2005.

Congress created section 216 to confront concerns that states were acting too slowly in siting new transmission lines needed to address growing reliability and congestion problems. In part, section 216 directs the DOE to study transmission congestion in consultation with the states, and designate certain transmission-constrained areas as national interest electric transmission corridors (“NIETCs”). Section 216 also grants the Federal Energy Regulatory Commission authority to issue permits to construct transmission facilities in these NIETCs under certain circumstances. Congress also provided that an applicant who receives a permit to construct transmission in a NIETC would be granted with the authority to acquire rights-of-way by eminent domain. In sum, section 216 had the potential to uncork the transmission bottleneck, but that potential has not materialized.

To continue reading, click here.

Texas Moves Ahead With New Transmission to Support Renewable Energy

From our colleague David Hattery:

In its year-end report, the Electric Reliability Council of Texas (ERCOT) outlined its program for an unprecedented build-out of high voltage lines to serve renewable energy projects. ERCOT will be overseeing the design and construction of more than 2,000 miles of new 345-kV transmission to serve additional wind capacity in remote areas of the ERCOT service area. The new projects are part of the Competitive Renewable Energy Zone (CREZ) program enacted by the Texas Legislature in 2005. The CREZ projects, which are expected to cost an estimated $4.9 billion, will provide access to deliver 18,500 MW of additional wind-generated power from the panhandle and west Texas to load centers in Dallas, Austin and San Antonio. In conjunction with the transmission projects, ERCOT recently completed the CREZ Reactive Power Study that recommends additional improvements necessary to control, condition, and route the additional renewable energy through the grid. Many of these projects are currently under construction and the entire CREZ program is scheduled to be complete by the close of 2013.

Links
ERCOT Report
CREZ Progress Report No. 2, January 2011

Come Learn What Every Renewable Energy Developer and Storage Provider Needs to Know About Integrating Variable Energy Resources

Wind & Solar Integration Summit, Scottsdale, AZ

January 24, 2011, 8 a.m. – 5 p.m., Workshop

January 25, 2011, 7 a.m. – 5:15 p.m., Conference

January 26, 2011, 9 a.m. – 11:45 a.m., Conference

 

As the Workshop Chair, I would like to extend you an invitation to the Wind & Solar Integration Summit, presented by Infocast. Join me and my colleagues in sunny Scottsdale, Arizona as we gather with industry experts—federal and state regulators, representatives from ISOs, independent power producers, and pioneers in energy storage—to discuss the challenges posed by renewable energy integration and the opportunities for businesses that make the necessary adjustments to prepare for the 21st century grid. We will be kicking off the conference with a keynote address by FERC Chairman, Jon Wellinghoff.

 

This 3-day event will include a pre-conference workshop on the fundamentals of integrating variable energy resources and electric energy storage (EES), and will feature a presentation by Stoel Rives partner and Conference Chair, Stephen Hall. The conference will address issues and recent developments in integration, including market solutions and investments to facilitate renewable energy integration, changes to the regulatory landscape, and the role of EES in enabling increased renewables integration. Stoel Rives partners Ed Einowski, Bill Holmes, and Jennifer Martin will present on managing the risks associated with curtailment and integration issues in PPAs. 

 

In case you need another good excuse to get to Arizona in January, Stoel Rives is currently offering a discount on registration. For more event details and registration information, please see: http://www.stoel.com/showevent.aspx?Show=7277

Projects & Money 2011

As we approach the beginning of a new year, financing options for energy projects (both conventional and renewable) under the current economic conditions continue to be a challenge and a focal point for the energy industry.  In order to gear up for financing opportunities in 2011,  I, along with my colleagues Marcus Wood, Graham Noyes and Adam Kobos, will be heading to the Big Easy for Projects & Money 2011.  Stoel Rives is proud to be a Gold Sponsor at this engaging conference, where Capital Providers, Project Developers and other dealmakers in the financing community will gather together to share information, discuss deal leads and capitalize on new market opportunities.

Projects & Money incorporates its comprehensive market updates with networking opportunities, introductions to new project developments, and interactive multimedia components. Presentations from industry professionals provide an inside look at some of the most ground-breaking deals of 2010, examine the trends they reveal, and provide a better understanding of what it takes to make deals happen.

Stoel Rives attorney Graham Noyes will present "DOE's Loan Guarantee Program: Crucial Financing Mechanism or a Costly Distraction?" on Tuesday, January 11, at 1:30 p.m. during the Pre-Summit Briefing.

On Wednesday, January 12, Partner Marcus Wood will moderate the discussion panel, "Transmission Outlook," at 2:15 p.m. during Track II: Project Sector Outlooks.

Hope to see you there!

To learn more about the conference or to register online, please visit: http://www.infocastinc.com/index.php/conference/416

Projects & Money
When: January 11-13, 2011
Where: Harrah's New Orleans – New Orleans, LA

Renewable Energy Law Alert: The Upper Midwest Reopens to Renewable Energy Development

Yesterday, December 16, 2010, the Federal Energy Regulatory Commission (FERC) conditionally approved a proposal by the Midwest Independent Transmission System Operator (MISO) that significantly changes how large transmission upgrades are funded across the MISO region.

MISO’s proposal creates a new category of transmission projects called Multi-Value Projects (MVPs) for upgrades that are determined to enable reliable and economic delivery of energy in support of public policy mandates or laws that address transmission reliability and congestion across multiple transmission zones.

MISO’s proposal is effective as of July 16, 2010 and thus applies to transmission projects identified in Appendix A of 2010 MISO Transmission Expansion Plan (MTEP).

To continue reading, click here.

If you have any questions about the order, how it may affect your generation or transmission project, or wind energy development in the Midwest, please contact one of the following attorneys:

Minneapolis, MN
Mark Hanson at (612) 373-8823 or mjhanson@stoel.com
Kevin Johnson at (612) 373-8803 or kdjohnson@stoel.com
Kevin Prohaska at (612) 373-8805 or krprohaska@stoel.com
David Quinby at (612) 373-8825 or dtquinby@stoel.com
Joe Thompson at (612) 373-8822 or jrthompson@stoel.com
Sarah Johnson Phillips at (612) 373-8843 or sjphillips@stoel.com

Portland, OR
Jennifer Martin at (503) 294-9852 or jhmartin@stoel.com
Marcus Wood at (503) 294-9434 or mwood@stoel.com
Sara Bergan at (503) 294-9336 or sebergan@stoel.com
Jason Johns at (503) 294-9618 or jajohns@stoel.com

FERC Decision Opens Door for New Wind Development in the Upper Midwest

The Federal Energy Regulatory Commission (FERC) opened the door today for new investment in transmission lines in the Upper Midwest that will deliver new wind energy to market.  By establishing a methodology for sharing the cost of new transmission lines, FERC’s decision could provide a significant boost to wind development in the region.  For more information, see our full alert.

Utah Energy Initiative Task Force Issues Draft Plan

On June 8, 2010, Utah Governor Gary Herbert launched a formal planning process for the Utah Energy Initiative.  Over the past several months the members of the Utah Energy Initiative Task Force and various subcommittees have conducted public hearings and a series of meetings to gather input for purposes of drafting a 10-year strategic energy plan.  The Energy Initiative Task Force issued a draft report on November 3, 2010.  Written comments on the draft report are due by November 10, 2010 and should be submitted to abuchholz@utah.gov.  A public hearing at which public comment will be accepted will be held on November 10, 2010 from 5:00 to 7:00 p.m., at the Senate Building (State Capitol complex east building), Room 215, Salt Lake City, Utah.

The energy plan outlined in the report contains the following themes:

  1. Economic Development and Energy Jobs
  2. Energy Development and Environment
  3. Energy Efficiency, Conservation and Demand-Response
  4. Transportation and Air Quality
  5. Transmission, Infrastructure and Transportation
  6. Developing and Applying Technology and Science

 

Continue Reading...

DOE Offers First Loan Guarantee for Transmission Project

DOE announced on October 19 its offer of a conditional commitment for a $350 million loan guarantee to develop the One Nevada Transmission Line (ON Line). ON Line consists of a new 500-kilovolt transmission line that will run 235 miles from Ely, Nevada to just north of Las Vegas. The project will carry approximately 600 megawatts (MW) of electricity, including renewable energy resources in northern Nevada. It will also integrate existing transmission systems in northern and southern Nevada, improving grid reliability and efficiency, and reducing power costs. This is the first transmission line project to be offered such a commitment by DOE's Loan Programs Office.

The ON Line project will be the first phase of the Southwest Intertie Project which, when fully completed, will carry approximately 2,000 MW of electricity and will enable wind and solar resources in Wyoming, Idaho, and Nevada to power the Southwest and California markets. The ON Line project is expected to contract about 85% of its parts and labor from U.S.-based companies, and it will create approximately 400 construction jobs.  

 

Report Identifies Transmission Corridors to Deliver 8,600 MW of New Wind in the Upper Midwest

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.

Stoel Rives Publishes White Papers on Transmission Development

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.

Sen. Kerry's Energy Tax Bill Would Help Energy Storage Technologies

On August 5, 2010, Sen. John Kerry (D-Mass.) introduced S.3738—the Clean Energy Technology Leadership Act of 2010—which would have some impact on the growth of energy storage technologies in the United States. 

Among other things, the bill would provide for an extension and modification of the Advanced Energy Manufacturing Tax Credit (the “MTC”), a credit authorized under the American Reinvestment and Recovery Act aimed at stimulating and expanding the domestic manufacturing industry for clean energy technologies.  The MTC is also referred to as Section 48C of the Internal Revenue Code (the “IRC”). The proposed modifications would extend the MTC to “statutory advanced energy property,” the definition of which includes property used exclusively to manufacture or fabricate fuel cell power plants and systems for the electrochemical storage of electricity (other than lead-acid batteries) for use in connection with electric grids. 

Also noteworthy is that S.3738 is similar to the STORAGE 2010 Act, introduced by Sens. Bingaman (D-NM), Wyden (D-OR), and Shaheen (D-NH) in July. Click here for more on that bill. Both bills amend Section 54C of the IRC to allow grid-connected energy storage systems to qualify for Clean Renewable Energy Bonds (“CREBs”). In addition to including energy storage technology in the CREBs program, S.3738 would expand the program by increasing the national new clean renewable bond limitation by $3.5 billion in 2010; sixty percent (60%) of that amount must be allocated by the Department of the Treasury to public power providers, and forty percent (40%) must be allocated to electric cooperatives. 

A major distinction between Sen. Kerry’s bill and the STORAGE 2010 Act is that Sen. Kerry’s bill does not add energy storage devices to the list of technologies eligible for the federal investment tax credit.  The full text of the bill can be found here.

Puget Wind Integration Charge REJECTED.

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.

 

FERC Comments on Electric Storage Technologies Due August 9

Just a friendly reminder that the deadline to submit comments to the Federal Energy Regulatory Commission (“FERC”) on electric storage technologies is just around the corner. In its Request for Comments Regarding Rates, Accounting and Financial Reporting for New Electric Storage Technologies, FERC’s Office of Energy Policy and Innovation seeks comments on the following issues: 

  1. The use of and rate treatment for storage facilities, including when it is appropriate to classify a storage facility as a transmission asset.
  1. The mechanisms by which a storage project that is used for multiple purposes may be compensated. Specifically, FERC seeks comment on whether a storage project may be compensated as transmission (e.g. for supporting unbundled transmission service by supplying reactive power) and also be compensated for providing ancillary services or for enhancing the value of merchant generation (e.g. by shifting output from an off-peak period to an on-peak period).
  1. The possibility of creating a stand-alone contract storage service and whether the storage provider would provide the service of electricity storage, enabling its customers to determine how to use their contracted share of the storage.
  1. Whether new accounting and reporting requirements should be created in order to facilitate cost of service or other rate policies for new storage technologies, such as chemical batteries and flywheels.

In addition to the issues outlined above and other specific questions posed by FERC in its Request for Comments, FERC invites comments on other related aspects of the storage issues not specifically addressed by FERC in the above-referenced document.  Comments are due on Monday, August 9, 2010 and should reference Docket No. AD10-13-000.     

Texas Court of Appeals Hands Down Decision in Important Wind Curtailment Case

On July 27, 2010, the Court of Appeals of Texas, Fifth District, Dallas, issued its decision in TXU Portfolio Management Company, L.P., v. FPL Energy, LLC, et al., 2010 Tex. App. Lexis 5905 (2010).  The case arose when three FPL wind farms (the "Wind Farms") located in the McCamey area of West Texas experienced ERCOT-imposed generation curtailments imposed by the Electric Reliability Council of Texas ("ERCOT") during 2002-2005.  The Wind Farms had each entered into a power purchase agreement (“PPA”) with TXUPM under which they agreed to deliver a minimum quantity of energy and renewable energy credits (RECs) each year. Because of the deficiencies caused by the ERCOT generation curtailments, TXUPM sued the Wind Farms for deficiency damages under the PPAs.  The Wind Farms counterclaimed, asserting that TXUPM materially breached each of the PPAs by failing to insure enough "transmission capacity" to allow the three wind farms to generate and deliver all of the electricity they were theoretically able to generate given wind conditions.

Section 2.03 of the PPAs required TXUPM to arrange for "all services, including without limitation Transmission Services . . . necessary to deliver Net Energy."  The Texas Court of Appeals concluded that this provision required TXUPM to supply transmission service sufficient to accept delivery of energy actually generated by the project and delivered to the interconnection point.  Contrary to the Wind Farms' argument, however, Section 2.03 did not require TXUPM to make sure there was enough transmission capacity in the McCamey area to make sure that the three wind plants could in fact generate every MWh they were theoretically capable of generating given wind conditions. 

This outcome is not too surprising--it would have been very unusual had the Court of Appeals concluded that an offtaker's duty to supply transmission services at the delivery point amounted to an implied duty to arrange for the construction of (very expensive) transmission infrastructure sufficient to avoid generation curtailments.  Utilities everywhere can breathe a sigh of relief that the Court of Appeals did not read this duty into the PPAs. 

The fact that the Wind Farms had failed to deliver enough output to meet the annual minimum quantities specified in  the three PPAs was not in dispute.  Since the court concluded that TXUPM had not breached the PPAs by failing to supply transmission capacity, the only remaining question was the calculation of damages. 

Stepping away from the court’s decision for a moment, though, it’s worth noting that there's a separate provision that is typically included in PPAs for intermittent renewable energy, and it apparently was not included in the three PPAs in dispute here, perhaps because of their 2000-2001 vintage.  An annual minimum output guarantee requires a wind developer to take both mechanical availability risk and wind risk--the plant's output can be reduced below the minimum level if the wind doesn't blow as hard or as often as expected, or if the wind turbines and other equipment are not available as often as they should be.  However, these risks are to some extent within the developer's control--wind risk can be addressed by thorough wind studies, and mechanical availability can be managed using the developer’s O&M program.   Generation and transmission curtailment, on the other hand, are typically outside the developer's control and can be affected by delays in completing transmission infrastructure, additions of other intermittent resources to the grid, routine maintenance of the transmission system, emergencies and other factors. 

Recognizing this, renewable energy PPAs usually provide that curtailed energy is counted as if it were generated for purposes of determining  whether a plant has achieved its output guarantees.  Although the requisite language is often omitted from utility pro forma renewable PPAs, most utilities are willing to agree if pressed that energy that could have been generated but for curtailment(s) should be counted as if it were generated for purposes of testing the project’s output guarantee. There may be a little scuffling over the proper method for calculating the quantity of energy and RECs that would have been generated “but for” the curtailment, but the real fight is usually over whether the PPA is in whole or in part a "take or pay" contract in which the utility is required to pay for some or all of the output that is actually curtailed. Cf. FPL Energy Upton Wind I, L.P., v. City of Austin, 240 SW3d 456 (2007), reh’g denied 2007 Tex App LEXIS 9306 (Tex App Amarillo 2007) (the Texas Court of Appeals ruled that ERCOT-imposed curtailments are not the same as voluntary economic curtailments by the power purchaser under a PPA and thus are not curtailments that the purchaser must pay for).

In any case, the Wind Plants in this case did not receive credit for curtailed energy under the three PPAs, so the court considered the deficiency as a given and turned to calculating the amount of damages.  The three PPAs had hard-wired $50/MWh as the liquidated damage payment due for each MWh of deficiency below the annual output guarantee.  This number was based on the per MWh penalty the Texas PUC was expected to impose, as of the time the PPA was entered into, on utilities that failed to secure enough renewable energy.  The Wind Plants argued that this amount bore no resemblance to TXUPM's cover damages at the time of the alleged breach and had persuaded the trial court to declare the liquidated damages clause to be unenforceable.  The Texas Court of Appeals reversed, concluding that the Wind Farms had failed to prove (1) that a measure of damages was ascertainable when the PPAs were entered into, or (2) that the $50/MWh rate was an unreasonable estimate of TXUPM's actual damages. 

Using the deficiency rate of $50/MWh and the Wind Farms' total net deficiencies of 580,465 MWh for 2002 through 2005, TXUPM claimed $29,023,250 in deficiency damages.  Bear in mind that these are just the deficiency damages, and thus only a part measure of the pain the plants suffered--they also had to forego a sale at the contract price and lost a Production Tax Credit (PTC) on each MWh curtailed.  For utilities that are slow to acknowledge that curtailment risk is an important issue for the intermittent energy developer, this case offers a very succinct $29 million dollar explanation of why developers, lenders, and equity care so much about the topic.

Colorado Public Utilities Commission Proposes New Rules Governing Transmission Planning

On July 28, 2010, the Colorado Public Utilities Commission (the "Commission") issued a Notice of Proposed Rulemaking ("NOPR") regarding rules related to electric transmission facilities planning (the "Proposed Rules").  The Proposed Rules are based, in large part, on the input provided by all interested parties in the workshops and written comments in connection with Docket Nos. 08I-227E and 09M-616E and in response to certain legislative and policy changes impacting transmission planning significantly.  In response to these legislative and policy changes, some of the key issues that need to be addressed in transmission planning include transmission-related challenges to satisfying State of Colorado's renewable energy portfolio standard for electricity generation, distributed generation set-asides, and requirements that the Commission give the fullest possible consideration to cost-effective implementation of new clean energy and energy efficient technologies.  In implementing the Proposed Rules, the Commission recognizes that "both state-wide coordinated transmission planning and a meaningful involvement in such planning by stakeholders and the Commission are essential."  NOPR at 2-3.  In addition, the Commission concluded that "an effective transmission planning approach needs to be long-term and pro-active rather than just-in-time and reactive."

Under the Proposed Rules, the Commission will rely on the Colorado Coordinated Planning Group ("CCPG") as the primary means by which jurisdictional electric utilities will develop the ten-year transmission plans and the twenty-year conceptual plans contemplated under the rules, in consultation with other CCPG members and stakeholders.  Overall, the Proposed Rules set forth the general objectives associated with the biennial filing of the following:  

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CPUC Staff Issues White Paper on Electric Energy Storage (EES)

Energy Electricty Storage (EES) is likely to become more and more important as intermittent solar and wind energy resources penetrate the grid.   EES may be a very useful and perhaps essential way to manage the variability of intermittent renewable energy resources to allow developers to continue building wind and solar projects at an accelerating pace.

On July 9, 2010, the Policy and Planning Division of the California Public Utility Commission (CPUC) issued an interesting Staff White Paper entitled "Electric Energy Storage: An Assessment of Potential Barriers and Opportunities." The report is worth reading for those who are interested in the future of renewable energy and the roll that EES can play in enhancing the deployment of intermittent renewables.

The report describes "a promising new set of Electric Energy Storage ("EES") technologies [that] appear to provide an effective means for addressing the growing problems of reliance on an increasing percentage of intermittent renewable generation resources."  The report observes that EES can provide several basice services, such as (1) supplying peak electricity demand by using electricity generated during periods of lower demand (e.g., storage of wind energy generated at night for use during daily peak periods), (2) balancing electricity supply and demand fluctuations over a period of minutes, and (3) deferring expansion of electric grid capacity (including generation, transmission and distribution). 

Potential storage technologies include pumped hydro, compressed air energy storage ("CAES"), batteries, thermal storage (e.g., solar thermal plants), flywheels, unltracapacitors and superconducting magnetic storage--the report provides short but helpful description of each technology.  Storage presents interesting legal and policy issues, because "[r]egulators are uncertain how EES technologies should fit into the electric system, in part because EES services provide multiple services such as generation, transmission and distribution."  In addition, "regulators do not yet know how EES costs and benefits should be allocated among these three main elements of the electric system." 

The report makes a number of recommendations, including that the CPUC should conduct a rulemaking to develop policies to remove barriers to the deployment of EES technology in California.  The report also proposes that the CPUC consider placing EES within California's energy resources loading order, require utilities to incoporate EES into their integrated resource planning processes, encourage CAISO to change ancillary service market rules to allow EES systems to more easily bid into regulation markets, and integrate EES into utility transmission planning.

The report concludes that "the major barrier for deployment of new storage facilities is not necessarily the technology, but the absence of appropriate regulations and market mechanisms that properly recognize the value of the storage resource and financially comepnsate the owners/operators for the services and benefits they provide."

You can find the report here.

CPUC Staff Issues White Paper on Electric Energy Storage (EES)

Energy Electricty Storage (EES) is likely to become more and more important as intermittent solar and wind energy resources penetrate the grid.   EES may be a very useful and perhaps essential way to manage the variability of intermittent renewable energy resources to allow developers to continue building wind and solar projects at an accelerating pace.

On July 9, 2010, the Policy and Planning Division of the California Public Utility Commission (CPUC) issued an interesting Staff White Paper entitled "Electric Energy Storage: An Assessment of Potential Barriers and Opportunities." The report is worth reading for those who are interested in the future of renewable energy and the roll that EES can play in enhancing the deployment of intermittent renewables.

The report describes "a promising new set of Electric Energy Storage ("EES") technologies [that] appear to provide an effective means for addressing the growing problems of reliance on an increasing percentage of intermittent renewable generation resources."  The report observes that EES can provide several basice services, such as (1) supplying peak electricity demand by using electricity generated during periods of lower demand (e.g., storage of wind energy generated at night for use during daily peak periods), (2) balancing electricity supply and demand fluctuations over a period of minutes, and (3) deferring expansion of electric grid capacity (including generation, transmission and distribution). 

Potential storage technologies include pumped hydro, compressed air energy storage ("CAES"), batteries, thermal storage (e.g., solar thermal plants), flywheels, unltracapacitors and superconducting magnetic storage--the report provides short but helpful description of each technology.  Storage presents interesting legal and policy issues, because "[r]egulators are uncertain how EES technologies should fit into the electric system, in part because EES services provide multiple services such as generation, transmission and distribution."  In addition, "regulators do not yet know how EES costs and benefits should be allocated among these three main elements of the electric system." 

The report makes a number of recommendations, including that the CPUC should conduct a rulemaking to develop policies to remove barriers to the deployment of EES technology in California.  The report also proposes that the CPUC consider placing EES within California's energy resources loading order, require utilities to incoporate EES into their integrated resource planning processes, encourage CAISO to change ancillary service market rules to allow EES systems to more easily bid into regulation markets, and integrate EES into utility transmission planning.

The report concludes that "the major barrier for deployment of new storage facilities is not necessarily the technology, but the absence of appropriate regulations and market mechanisms that properly recognize the value of the storage resource and financially comepnsate the owners/operators for the services and benefits they provide."

You can find the report here.

New Tool for Renewable Energy Investors, Entrepreneurs, and Companies

On June 30, 2010, the U.S. Department of Energy ("DOE") launched its Technology Commercialization Portal (the "Portal").  The Portal is an online resource that provides a mechanism for investors, entrepreneurs and companies to identify new technologies coming out of DOE laboratories and other participating research institutions.  Relevant technologies include:

  • Advanced Materials
  • Biomass and Biofuels
  • Building Energy Efficiency
  • Electricity Transmission and Distribution
  • Energy Analysis Models, Tools and Software
  • Energy Storage
  • Geothermal
  • Hydrogen and Fuel Cell
  • Hydropower, Wave and Tidal
  • Industrial Technologies
  • Solar Photovoltaic
  • Solar Thermal
  • Vehicles and Fuels
  • Wind Energy

The Portal contains marketing summaries about the various DOE technologies that are available for licensing.  Each marketing summary describes a technology's applications, advantages, benefits and state of development.  Further, the Portal also provides access to information on patents and patent applications that have been created using DOE funding since 1992.

The Portal is located at http://techportal.eere.energy.gov/

Midwest ISO Final MVP Cost Allocation Proposal Won't Charge Generators for New Transmission Needed for Wind Energy

From our colleague Sarah Johnson Phillips:

Much to the relief of wind developers in the Midwest, the Midwest ISO has backed off a plan to charge new and existing generators 20% of the cost of new transmission needed to meet renewable energy development goals.

Yesterday, the Midwest ISO released its final cost allocation proposal, which it will file with the Federal Energy Regulatory Commission on July 15, 2010. In the final proposal, the cost of Multi-Value Projects (MVPs) will be spread evenly to load throughout the MISO footprint on an energy basis. MVPs are transmission projects needed to support renewable energy development, other policy drivers, or have multiple benefits such as reliability and market efficiency. Previous cost allocation proposals would have allocated 20% of the cost of MVPs to new and existing generators. That potential cost burden and resulting cost uncertainty had caused some wind industry observers to speculate that wind projects would abandon the Midwest for other parts of the country where transmission is cheaper.

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Kauai's Electric Utility Faces Civil Suit and Criminal Charges For Bird Fatalities

From our colleagues Greg Corbin and Barbara Craig:

On March 24, 2010, four conservation groups filed a complaint against Kauai’s electric utility, Kauai Island Utility Co-op (“KIUC”), alleging that KIUC’s power lines, utility facilities, and street lights “take” threatened Newell’s Townsend’s shearwaters (Puffinus Auricularis Newelli) (“Newell’s shearwaters”) and/or endangered Hawaiian petrels in violation of the Endangered Species Act (“ESA”). The civil complaint, filed in the U.S. District Court for the District of Hawaii, alleges that KIUC has failed to secure the necessary ESA incidental take permits and, despite years of promises, has failed to implement protective measures that are needed to prevent the “take” of the listed birds.

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Release of the "Western Wind and Solar Integration Study"

The National Renewable Energy Laboratory ("NREL") recently announced the release of the "Western Wind and Solar Integration Study"  (the "WWSIS"), which investigated the operational impact of up to 35% energy penetration of wind, photovoltaic, and concentrating solar power on the power system operated by the WestConnect group of utilities in Arizona, Colorado, Nevada, New Mexico and Wyoming.  The WestConnect group includes the following:  Arizona Public Service, El Paso Electric Co., NV Energy, Public Service of New Mexico, Salt River Project, Tri-State Generation and Transmission Cooperative, Tucson Electric Power, Western Area Power Administration, and Xcel Energy.

The WWSIS was prepared by GE Energy and conducted over two and a half years by a team or researchers in wind power, solar power, and utility operations.   The WWSIS was designed to answer questions that utilities, Public Utility Commissions, developers, and regional planning organizations had about renewable energy use in the West, such as:

  • What is the operating impact of up to 35% renewable energy penetration and how can this be accommodated?
  • How does geographic diversity help to mitigate variability?
  • How do local resources compare to remote, higher quality resources delivered by long distance transmission?
  • Can balancing area cooperation mitigate variability?
  • How should reserve requirements be modified to account for the variability in wind and solar?
  • What is the benefit of integrating wind and solar forecasting into grid operations?
  • How can hydro generation help with integration of renewables?

 

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TransCanada challenges Massachusetts RPS

Stoel Rives litigation partners Beverly Pearman and Jeremy Sacks have prepared the following report on TransCanada’s recent challenge to the Massachusetts RPS:

On April 16, 2010, TransCanada Power Marketing, Ltd. (“TransCanda”) filed suit in the U.S. District Court for the Central District of Massachusetts arguing that Massachusetts is unconstitutionally discriminating against out-of-state renewable energy producers. TransCanada purchases energy from generators and resells it to distribution companies and retail customers in the northeast United States. It is a U.S.-based subsidiary of TransCanada Corporation, a Canadian entity that, among other things, owns significant pieces of energy infrastructure in Canada and the United States, including power generation facilities. TransCanada’s suit challenges two Massachusetts programs that it claims benefit in-state economic interests while burdening out-of-state interests in violation of the U.S. Constitution’s Commerce Clause. It is seeking declaratory and injunctive relief as well as damages under 42 USC § 1983.

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Tradable RECs Now Count Toward California's RPS

On Thursday March 11, 2010, the California Public Utility Commission (the "CPUC") created a market for tradable renewable energy credits ("TRECs") in the state.  That's big news.  In its 149-page decision, the CPUC stated that investor-owned utilities ("IOUs"), energy service providers, and community choice aggregators may now use TRECs to comply with California's ambitious renewable portfolio standard ("RPS").  These entities are now permitted to purchase a portion of their RPS compliance from generation sources other than those they own (e.g., distributed solar generation facilities within the state and certain out-of-state facilities).

 

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Treasury Creates Safe Harbor for Smart Grid Investment Grants

Yesterday, the Energy and Treasury Departments jointly issued guidance regarding the federal income tax treatment of Smart Grid Investment Grant payments received pursuant to the American Recovery and Reinvestment Act (ARRA).

The guidance, which was issued as Revenue Procedure 2010-20, generally provides that a corporation receiving a specified grant will not recognize taxable income upon receipt of the grant, but will be required to reduce the tax basis of its assets by the amount of the grant.

Stoel Rives issued a law alert today regarding this guidance, further exploring what the guidance addresses, and notably, does not address.

FERC Determines That Battery Storage Devices Qualify as Transmission Facilities. Is the Door Open for Other Energy Storage Devices?

In late January, FERC issued an order in response to a filing by Western Grid Development LLC that asked FERC to declare that Western Grid's proposed battery storage devices are transmission facilities eligible for certain rate incentives.  Western Grid described its battery technology as 10 to 50 MW sodium sulfur batteries that would be installed at strategic places on the California ISO transmission grid in order to provide voltage support and protect against transmission overloads.  In a description that seemed significant to FERC, Western Grid stated that its batteries would only enhance transmission reliability at the California ISO's direction, and that the batteries would not operate or participate in energy markets or provide electricity for commercial sale. 

FERC examines energy storage devices on a case-by-case basis because storage devices don't fit squarely within the traditional transmission, distribution, or generation categories of assets.  In this case, FERC gravitated to the notion that the battery devices would not provide capacity or energy to be sold in the energy market, and that Western Grid would not retain any revenues outside of the transmission access charge (unlike generators).  For these and other reasons, FERC distinguished Western Grid from similar filings (see Nevada Hydro II--pumped storage), and determined that Western Grid's technology will act enough like transmission assets to warrant eligibility for transmission rate incentives.  FERC's approval of rate incentives, however, was conditional upon the California ISO approving Western Grid's projects in the transmission planning process. 

Although FERC repeated numerous times that its decision was based on the "specific circumstances and characteristics" of Western Grid's projects, the order shows potential for energy storage devices.  If such devices can show that they act sufficiently like traditional transmission assets (like capacitors), they may be able to obtain very valuable transmission rate incentives.  Whether this opens the door for compressed air energy storage and pumped hydro (but see Nevada Hydro II) is still up in the air, but rest assured that these questions will be at FERC before too long.