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.
Converting a qualifying facility's legacy PURPA interconnection agreement to a FERC-jurisdictional agreement can be an effective way to bypass the numbing headache that often accompanies taking a new power generation project through the interconnection queue. One may even be able to throw in a repower and, voila!, you have a refreshed facility that can operate for decades more in broader bilateral power markets without having years of interconnection delay.
But there are ins-and-outs to these conversions, and today FERC addressed the question of whether a qualifying facility owner may necessarily convert the capacity that's stated in its PURPA interconnection agreement. For qualifying facility owners--it isn't the answer you wanted.
See FERC's order by following this link: CalWind Order.
Like other Independent System Operators have done before it, the Southwest Power Pool (SPP) is back at the drawing board in an effort to further refine its generator interconnection procedures and improve on queue reforms initially put in place in 2009. And also like other ISOs that have continued to tinker with queue reform, SPP is looking to make the interconnection process more demanding so that only the "viable" projects get through.
Among the various proposed changes, there are a few that generation developers should key in on.
- SPP proposes to allow later-queued customers pass by higher-queued customers in terms of queue priority, provided that the later-queued customer is the first to reach the Facilities Study phase. Previously, customers who reached the DISIS queue could not lose their queue priority and be passed by. But now priority goes to customers who reach the Facilities Study first. This change, of course, will impact customers' cost responsibilities, as priority to unused transmission capacity will be subject to the race to the top.
- To enter the Facilities Study phase (and lock in queue priority), customers must complete a financial milestone by providing security equal to $3,000 per megawatt of the generator size. SPP has proposed removing other choices that customers previously used for entering this phase of the study process. But watch out--customers who later withdraw from the queue may forfeit this deposit.
- Prior to signing an interconnection agreement, an interconnection customer may extend its commercial operation date by no more than three years. Anything longer will be considered a material modification and will result in a loss of queue position.
- Under proposed revisions to the interconnection agreement, a customer would have three years following its designated Commercial Operation Date to complete its generating facility. A customer who fails to do so will have its interconnection agreement terminated. In addition, customers who fail to bring their full generation capacity online within that timeframe will lose rights to any capacity that remains unused at the three-year mark.
- Lastly, customers who sign an interconnection agreement must post 20% of the costs of their network upgrades within 30 days of execution. This deposit may be non-refundable under certain circumstances.
Given the queue reforms that FERC has accepted in other regions, it's likely that much of what SPP has proposed will make it into the tariff.
SPP has asked that these latest reforms be made effective March 1, 2014, and applicable to any customer who does not have an interconnection agreement with an earlier effective date. For those customers currently negotiating an interconnection agreement: the race is on.
With the holidays behind us and the cheer and reverie of the New Year trailing off, wind developers in Idaho may be realizing that the Federal Energy Regulatory Commission (FERC) left a lump of coal in their stockings on Christmas Eve. On December 24, FERC agreed to dismiss an historic legal action that it had taken to enforce the Public Utility Regulatory Policies Act of 1978 (PURPA) against the Idaho Public Utilities Commission (IPUC) on behalf of Qualifying Facility (QF) wind developers who have been beaten up by numerous decisions coming out of the state agency over the past several years. FERC had never before sought to enforce PURPA against a state agency, but the IPUC apparently found FERC’s tipping point.
In exchange for its agreement to dismiss this first-of-its-kind action, FERC extracted a simple acknowledgement of questionable value from the IPUC: “The Idaho PUC acknowledges that a legally enforceable obligation may be incurred prior to the formal memorialization of a contract to writing.” And that is as far as their substantive agreement goes. In other words, the IPUC acknowledges that a hypothetical situation may occur, without agreeing to the all-important question of when that situation does occur. The agreement signals an apparent policy change at FERC, and it also leaves QF wind developers on their own, once again, to enforce PURPA in protracted litigation in federal court, i.e., without a viable option.
For those keeping score, there was none in this dispute: FERC threw in the towel before the first bell.
Thousands of solar industry participants gathered in Chicago for the Solar Power International expo in Chicago, Illinois on October 21-24 to discuss the state of the solar industry. Participatnts included banks, investors, developers and equipment suppliers, and also several Stoel Rives attorneys.
Many themes emerged during the week-long event, and a common thread running through these themes was “change.” The solar industry is undergoing significant changes, as demonstrated by the following:
- Stoel Rives announced that Federal Energy Regulatory Commission Chairman Jon Wellinghoff will join the firm later this year following his impending resignation from the Commission;
- The regulatory environment continues to morph as the 1603 cash grant phases out while the ITC reemerges pending its expiration, net-metering battles rage on in multiple states, and California has required investor owner utilities to procure and invest in significant amounts of energy storage;
- Companies continue to search for investment grade projects while developers continue to hunt for PPAs with sustainable pricing;
- Chinese equipment manufacturers continue to factor in the space, and several companies from mainland China attended the expo for the first time, now also joined by a growing number of Taiwanese and Korean companies;
- As utility scale development opportunities in the United States continue to stagnate, many companies are turning their focus to Latin America where new and potentially lucrative opportunities are emerging;
- The industry seems ripe for consolidation and the remainder of 2013 and 2014 may witness several significant mergers.
In this time of significant change, Stoel Rives will continue to serve the solar industry by providing high quality legal services and innovative solutions for the issues of today and the issues of the future.
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.
Our firm today announced that Jon Wellinghoff, Chair of the Federal Regulatory Commission (FERC), will join Stoel Rives LLP upon completion of his service at FERC. As many of our readers will recall, Jon submitted his resignation to the President on May 28, 2013. No date has been announced for his departure from FERC.
For press inquiries, contact:
Gregory F. Jenner, Partner, (202) 398-1794
Alan R. Merkle, Chairman, (206) 386-7636
Judy L. Rooks, Marketing Communications Mgr., (503) 294-9831
The United States Court of Appeals for the Seventh Circuit recently issued a decision in Illinois Commerce Commission, et al., v. Federal Energy Regulatory Commission (“FERC”), which has the potential to influence and provide direction for the federal district court currently considering the constitutionality of Minnesota’s Next Generation Energy Act (“NGEA”). In Illinois Commerce Comm’n, the Seventh Circuit heard a challenge to FERC’s approval of the Midcontinent Independent System Operator, Inc.’s (“MISO’s”), Multi-Value Project (“MVP”) tariff for financing new high-voltage power lines. As noted here, the constitutionality of a Michigan statute was questioned by the Seventh Circuit.
Michigan’s Clean, Renewable, and Efficient Energy Act prohibits utilities from using renewable energy generated outside of the state to satisfy the requirement that the utilities’ retail supply portfolios include at least ten percent renewable energy by 2015. A group of petitioners argued that, as a result of this statutory provision, Michigan ratepayers would pay costs well in excess of any benefits they derive from MVPs, in violation of the long-standing cost causation principle. In response, the Seventh Circuit stated that "Michigan cannot, without violating the commerce clause of Article I of the Constitution, discriminate against out-of-state renewable energy."
This statement from the Seventh Circuit could implicate other statutes that treat power generated out-of-state differently than power generated in-state. One such statute is the NGEA. Passed in 2007, the NGEA mandates that (1) Minnesota's fossil fuel use be reduced by 15% by 2015, and (2) renewable energy sources account for 25% of the state's total energy use by 2025. In order to achieve these goals, the NGEA prohibits any person (1) from constructing in Minnesota a “new large energy facility that would contribute to statewide power sector carbon dioxide emissions”, (2) “import[ing] or commit[ting] to import from outside the state power from a new large energy facility that would contribute to statewide power sector carbon dioxide emissions”, and (3) “enter[ing] into a long-term power purchase agreement that would increase statewide power sector carbon dioxide emissions.” These prohibitions were recently challenged by the State of North Dakota and other complainants in the United States District Court, District of Minnesota.
In North Dakota v. Swanson, North Dakota claimed that the NGEA violates the Commerce Clause by facially discriminating against and unduly burdening interstate commerce. Although the case is still in the early stages, some commentators believe that the decision in Illinois Commerce Comm’n “will have serious echoes” across the country that could jeopardize statutes like the NGEA that are currently facing challenges, both judicial and legislative. Others predict that the Seventh Circuit's decision will have a minimal impact on the NGEA's validity because the court’s language was arguably dicta and the cases cited, such as Alliance for Clean Coal v. Miller and Wyoming v. Oklahoma, do not necessarily stand for the proposition that discrimination against out-of-state coal violates the Commerce Clause when states favor renewable energy over other types of electrical generation. With the deadlines stretching into 2014, the federal judge in North Dakota v. Swanson will have plenty of time to consider the Illinois Commerce Comm’n case and its potential applicability to the NGEA.
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.”
In September 2012, all new electricity generation came from solar and wind projects, according to the Energy Infrastructure Update (PDF) issued by the Federal Energy Regulatory Commission’s Office of Energy Projects. Five wind projects totaling 300MW and 18 solar projects totaling 133MW came online during the month.
The Energy Infrastructure Update also noted that nearly half (43.8%) of new generating capacity coming online in 2012 through September involve renewables: 77 wind projects (4,055 MW), 154 solar projects (936 MW), 76 biomass projects (340 MW), 7 geothermal projects (123 MW), 10 water power projects (9 MW), and one waste heat project (3 MW).
The looming expiration of the Section 1603 Treasury Cash Grant and the Production Tax Credit (PTC) is likely a significant driver of this end of year surge. See our October 18 post Economists Weigh in on the PTC Extension for our latest on the PTC.
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 Confirms That Its "One-Mile" Rule is a Safe Harbor for Establishing Separate Qualifying Facilities
The Federal Energy Regulatory Commission's (FERC) regulations provide that, for purposes of calculating a qualifying facility's net capacity, generating facilities are considered together as a single qualifying facility if they are located within one mile of each other, use the same energy resource, and are owned by the same persons or their affiliates. In recent years, landowners and energy purchasers have disputed whether the location of generating facilities more than one mile apart is a "safe harbor," ensuring that the facilities will be treated as separate qualifying facilities, or is instead a rebuttable presumption that may be challenged. In its Order Denying Rehearing, issued June 8, 2012 in Docket Nos. EL11-51-001, QF10-649-002, and QF10-687-001, FERC reaffirmed that the one-mile separation standard provides a safe harbor for establishing separate qualifying facilities.Continue Reading...
In October 2011, the Federal Energy Regulatory Commission (FERC) issued Order No. 755, which requires regional transmission organizations (RTOs) and independent system operators (ISOs) to pay for frequency regulation services based on the actual amount of service provided in response to actual or expected frequency deviations or interchange power imbalances. The order directs RTOs and ISOs to implement a two-part payment for frequency regulation services consisting of (1) a capacity payment that includes the marginal unit's opportunity costs, and (2) a performance payment that reflects the quantity of frequency regulation service that a resource provides when it is accurately following the dispatch signal. In February 2012, FERC issued Order 755-A, denying a motion for rehearing filed by Southern California Edison.
On Tuesday April 10, 2012, 11 am to 12:30 pm Eastern time (8 am to 9:30 am Pacific), I'll be moderating a Webinar produced by that Infocast to discuss the implications and effect of Order No. 755. We'll review the Order itself, the process that is underway in the RTOs and ISOs to implement the Order, and the Order's implications for energy storage, demand response and other aspects of the frequency regulation market.
Infocast has assembled an excellent panel for this Webinar. Jacqueline DeRosa, Director of Regulatory Affairs, California, Customized Energy Solutions and Rahul Walawalkar, PhD, CEM, CDSM, Vice President, Emerging Technologies Markets, Customized Energy Solutions, will jointly provide a cross-market overview of the current approaches and proposed responses to Order No. 755 in key ISOs and RTOs (i.e., PJM, NYISO and CAISO) . Eric Hsieh, Regulatory Affairs Manager, A123 Systems, Inc., (which participated actively in the Order No. 755 docket) will offer a technology provider's perspective on the order and the ongoing process. Praveen Kathpal, Director of Marketing and Regulatory Affairs, The AES Corporation, will provide the perspective of a technology-neutral independent energy storage developer.
You can register for the Order No. 755 conference here. Use the Stoel Rives discount code (“128505”) to reduce the tuition to $150.
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.
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.
The Interconnection Landscape Changes Yet Again: FERC Conditionally Accepts the California ISO's Interconnection Queue Reform Phase 2
On January 31, 2012, the Federal Energy Regulatory Commission (FERC) conditionally accepted additional reforms to the California ISO’s Generator Interconnection Procedures (GIP) that significantly change the rules that apply to developers seeking to interconnect power generation facilities in the California ISO’s balancing authority area.
The decision continues the California ISO’s efforts to reform the GIP that began in 2008, and focuses on 18 specific issues that arose from stakeholder efforts, interconnection agreement negotiations, the California ISO’s transmission planning process, or that were carried over from the previous round of reforms.
The reforms addressed the following issues and more:
• Deliverability Status
• Financial Security Deadlines
• Posting of Security and Reimbursement of Costs for Network Upgrades
• Reductions in Project Size
To learn more about the reforms approved yesterday and how they may affect your generation development plans, please contact one of the attorneys listed below.
Maurcus Wood at (503) 294-9434 or email@example.com
Seth Hilton at (415) 617-8943 or firstname.lastname@example.org
Jason Johns at (503) 294-9618 or email@example.com
Chad Marriott at (503) 294-9339 or firstname.lastname@example.org
Today, the Federal Energy Regulatory Commission ("FERC") issued its first pilot project license for a tidal energy project to Verdant Power, LLC for its Roosevelt Island Tidal Energy ("RITE") Project in New York's East River (pictured at right). As a first-of-its-kind license, this is a significant step for the burgeoning tidal energy industry in the United States.
According to the license, the project will be construted in three phases over a five year period. When complete, the project will consist of thirty 35-kW, 5-meter-diameter axial flow Kinetic Hydropower System ("KHPS") turbines with a total installed nameplate capacity of 1.05 MW. Verdant must begin construction on Phase 1 within the next two years and must complete Phase 3 within six years. The license was issued for the full 10 years requested in Verdant's license application.
Although the levelized cost of energy for the RITE project is high relative to other energy sources, the Commission stated clearly that "[t]his project's value . . . lies in its successful testing and demonstration of Verdant's KHPS turbine technology, and the project's ability to raise the profile of, and advance, the emergent tidal energy industry."
The license can be found on FERC's website under Docket No. P-12611-005.
For more detailed information on the FERC pilot project licensing process, see Chapter 3 of our recently updated Law of Marine and Hydrokinetic Energy.
On December 7, 2011, the Federal Energy Regulatory Commission issued an order holding that the Bonneville Power Administration violated Section 211A of the Federal Power Act by curtailing wind energy under BPA’s Environmental Redispatch policy and requiring BPA to file a revised transmission tariff within 90 days from the date of the order.
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.
This summer, the Center for Public Service at the Hatfield School of Government at Portland State University will be offering a series of short, 2-3 day classes under an umbrella called the "Summer Series on the New Energy Economy." These are non-credit courses, specifically designed for energy industry leaders, a wide range of professionals, and other community members with an interest in learning more about key energy topics.The series is being coordinated by Jeff Hammarlund, one of PSU’s adjunct faculty, who in recent years has taught a series of popular classes on various aspects of the Smart Grid.
The summer series will kick off with the first class on July 11-12. Entitled "Dissolving Complex Problems in the New Energy Economy," this course will bring a systems science focus to core energy structure, regulation, and policy questions. Other classes, which will run in July, August, and September, include
* Green Inc: Business Models for the New Energy Economy (July 13-15);
* Comprehending the Climate Conundrum (July 25-27);
* Riding the Waves of Change: Project Management and the New Energy Economy (August 10-12); and
* The Smart Grid and Sustainable Energy Systems (September 14-16);
Additional information and registration instructions can be found here. If you have specific questions, contact Christine Hanolsy at PSU at 503-725-5114 or email@example.com.
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 firstname.lastname@example.org. 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.
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!
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.
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.
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.
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.
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.
FERC and Feed-in Tariffs: Opportunities and Challenges in California and Other States Webinar - March 2, 2011
FERC and Feed-in Tariffs: Opportunities and Challenges in California and Other States
Wednesday, March 2 at 11:00 a.m. CST/ 9:00 a.m. PST.
After prolonged consideration by the California Public Utilities Commission, California recently adopted a reverse auction mechanism for renewable energy projects 20 megawatts or smaller. That program initially arose from the California Public Utilities Commission's efforts to expand an existing feed-in tariff program and was structured as a reverse auction mechanism to avoid potential conflicts with Federal Energy Regulatory Commission (FERC) jurisdiction. This webinar will explore feed-in tariffs and similar programs, such as California's Renewable Auction Mechanism. It will also address the Federal Energy Regulatory Commission's decision in October concerning the California Public Utilities Commission's proposed feed-in tariff for combined heat and power generators, as well as the implications of that decision for feed-in tariff design.
- Discuss feed-in tariff policies, including benefits and drawbacks
- Analyze FERC's decision on California's feed-in tariff for combined heat and power generators
- Recognize the implications of FERC's decision on feed-in tariff design
- Examine California's Renewable Auction Mechanism and feed-in tariff
- Compare California's feed-in tariff with those in other states while examining feed-in tariff success in other states