In a first-of-its-kind report announced this morning, Ceres and Clean Edge ranked the nation's largest electric utilities and local subsidiaries on their renewable energy sales and energy efficiency savings. The report focused on three clean energy indicators: renewable energy sales; cumulative annual energy efficiency; and incremental annual energy efficiency.
We wanted to invite our readers to listen in on a one-on-one conversation between our colleague Jon Wellinghoff and Marty Rosenberg, EnergyBiz editor-in-chief, July 15, noon-1 p.m. Eastern. You can register here.
Jon, the immediate past chair of FERC, helped initiate a national debate about grid security when he raised concerns in a Wall Street Journal article titled “Assault on California Power Station Raises Alarm on Potential for Terrorism” published last February. Register and hear Jon speak on these important matters:
- What is FERC doing on the cybersecurity front?
- What is the role of smart grid and renewables in security?
- What is the role of microgrids in security?
During today's open meeting, the Federal Energy Regulatory Commission (FERC) issued a proposed rulemaking that impacts the owners of gen-tie lines, particularly those owners who are developing multi-phase projects that require priority to interconnection capacity to support future phases. The proposed rule would ease existing FERC policies that treated gen-tie lines just like any other transmission facility and required owners to make interconnection capacity available to third parties if the owner could not provide enough documentation proving its planned use of the gen-tie lines.
FERC has proposed the following:
- Gen-tie line owners will be granted a blanket waiver from the requirement to (x) maintain a transmission tariff and OASIS and (y) comply with the standards of conduct. FERC will revoke that blanket waiver only when it is in the public interest to do so, and not simply when a third party requests transmission service over a gen-tie line.
- Third parties seeking to interconnect with existing gen-tie lines will be required to do so using the rules and regulations applicable to service requests under sections 210 and 211 of the Federal Power Act.
- Gen-tie owners who are eligible for the blanket waiver from maintaining a tariff, etc., will be granted a 5-year safe harbor period giving the owner the benefit of a rebuttable presumption that (1) the owner has plans to use the gen-tie line's capacity, and (2) the owner should not be required to expand its facilities. Third parties would have an opportunity to rebut that presumption, but those third parties would have the burden of proof. FERC proposes that the 5-year period would begin on the gen-tie energization date. Gen-tie owners would also be required to make an informational filing with FERC in order to take advantage of the safe harbor rights.
- Lastly, FERC has asked whether the affiliates of public utility transmission provider should receive the benefit of the proposed rules.
The proposed rulemaking is available here: Gen-Tie Rulemaking
Comments are due by 60 days after publication of the proposed rule in the Federal Register. Please let us know if you have questions about the proposed rulemaking and/or would like to submit comments to FERC.
The East Kern Wind Resource Area (EKWRA)--it's a mouthful--and it's also a hotbed for renewable energy development and the location of a fight over millions of dollars among Southern California Edison (SCE), the California ISO, and independent power developers (IPPs). Late last week, the Federal Energy Regulatory Commission (FERC) scored that fight in favor of SCE and the California ISO.
For the past few years, SCE has been working to reconfigure the transmission system in the EKWRA region in order to address a reliability issue occurring there. But the reconfiguration would have another impact--it would modify the transmission system in the area so that it became a distribution system under SCE, rather than CAISO, control. To IPPs, that modification came with significant cost consequences: in the interconnection process, IPPs funding network upgrades on the transmission system receive a full reimbursement for the cost of those upgrades; distribution upgrades, on the other hand, result in no reimbursement. For IPPs who had assumed they would be reimbursed the network upgrade costs that appeared in their interconnection agreements (which often cost a single project millions of dollars), it came as something of a surprise when they learned that the reconfiguration might cause their reimbursements to dry up.
And so the IPPs challenged SCE and the California ISO. In its decision, FERC determined that the reconfigured EKWRA facilities are distribution, or non-integrated facilities, and that the California ISO correctly transferred control over the facilities to SCE's tariff. As a result, no further reimbursements to the IPPs will occur. "Despite being informed of the possibility of reclassification, [the IPPs] made a business decision to proceed with interconnection." For some IPPs, this could have a very costly impact.
You can read the entire order here: EKWRA Order.
In a proposed decision issued yesterday from the California Public Utilities Commission, an administrative law judge (ALJ) determined that energy storage devices (i) that are paired with net energy metering- (NEM) eligible generation facilities, and (ii) that meet the Renewables Portfolio Standard Eligibility Guidebook requirements to be considered an "addition or enhancement" to NEM-eligible systems are "exempt from interconnection application fees, supplemental review fees, costs for distribution upgrades, and standby charges when interconnecting under current NEM tariffs.
The issue of whether solar PV-integrated energy storage could interconnect through NEM tariffs heated up in recent months as utilities in California determined that such systems were not NEM-eligible and therefore imposed additional requirements (and costs) in order for a paired solar PV system itself to be NEM-eligible. These requirements and costs acted as a barrier to using energy storage technologies with distributed generation. But in this proposed decision, the ALJ encouraged the state's utilities to take a "more proactive and collaborative approach to avoid creating barriers," and found that energy storage should be exempt from these additional requirements when certain conditions are met.
Sizing. The proposed decision states that NEM-paired storage systems with storage devices sized at 10 kW or smaller are not required to be sized to a customer's demand or the NEM generator. For NEM-paired storage systems with storage larger than 10 kW, (x) the discharge capacity of the storage system may not exceed the NEM generator's maximum capacity, and (y) the maximum energy discharged by the storage device shall not exceed 12.5 hours of storage per kW.
Metering. With respect to metering requirements, the proposed decision again draws distinctions between storage systems above 10 kW discharge and those at 10 kW and below discharge capability, although the decision proposes to impose certain requirements on both categories in order to "preserve the integrity of NEM." For systems at 10 kW and below, the decision proposes using a de-rate factor to measure the AC energy that flows into, and out of, the NEM generator. NEM-paired systems larger than 10 kW will be required to adhere to metering requirements similar to those under the NEM Multiple Tariff Facilities provision of utilities' NEM tariffs, although the costs of metering will be capped at $500. In either category, the proposed requirements aim to ensure that only NEM-eligible generation receives NEM credit.
The full proposed decision may be viewed here: CPUC Proposed Decision re Energy Storage
Ameren Should LOSE the Latest Battle Over Option 1 Network Upgrade Funding in the Midcontinent ISO Region
Ameren is at it yet again--perpetuating a method for funding generator interconnection network upgrades in MISO that the Federal Energy Regulatory Commission (FERC) found to be unjust, unreasonable, and discriminatory over three years ago. Ameren has already won two cases that allowed it to continue using Option 1 funding for certain interconnection customers. But Ameren should lose this one. Here's why:
A Brief History. Prior to March 22, 2011, the MISO tariff provided three methods for funding interconnection network upgrades. Option 1 required an interconnection customer to upfront fund the cost of network upgrades (post security and pay monthly construction costs); when those upgrades became commercially operational, the transmission owner would reimburse the full amount paid by the customer and then establish a transmission rate to charge the customer for using the upgrade on an ongoing basis. Option 2 funding also required the customer to pay upfront construction costs, but then the customer was reimbursed a portion of those costs following commercial operation. Option 2 did not include an ongoing rate. As a result, over time Option 1 funding could result in multiples of the actual cost that a customer might pay under Option 2. (The third option--"self-fund"--allowed a transmission owner to pay upfront costs itself and then charge a usage rate.)
On March 22, 2011, FERC responded to a complaint about Option 1 funding by independent power producers, determining that the method was "unjust, unreasonable, and discriminatory." FERC ordered MISO to remove Option 1 funding from its tariff. That order is found here: E.ON Climate & Renewables.
However, in the past couple of years, Ameren has successfully won the right to continue using Option 1 funding in interconnection agreements that were signed prior to FERC's decision in E.ON. After FERC issued its decision in E.ON, certain customers attempted to obtain the benefit of that decision by having FERC alter their agreements where they had agreed to Option 1 funding. But FERC denied the attempts, primarily on the basis that those prior agreements expressly provided for Option 1 funding and that it would not be in the public interest to unilaterally modify the contracts. In other words, those customers who sought to benefit from the E.ON decision had express notice that Option 1 funding would apply and they failed to raise a timely dispute; FERC would not reset the contracts they had agreed to. Those decisions are available here: Rail Splitter (agreed to Option 1 funding by signing a Facilities Service Agreement) and Hoopeston (agreed to Option 1 funding in its interconnection agreement).
Now we come to the current dispute over Option 1 funding. This docket focuses on an interconnection agreement that Ameren signed with White Oak Energy in 2007. At that time, Option 1 funding existed under the MISO tariff, but White Oak's interconnection agreement said nothing expressly about Option 1 funding. In addition, Ameren was not required to select the funding method until the network upgrades reached commercial operation. At the time of signing its interconnection agreement, if White Oak had disputed the potential application of Option 1, FERC would have likely dismissed the dispute for being unripe. It wasn't a real issue yet.
Fast forward four years. Ameren completed construction of White Oak's network upgrades in 2011 and notified White Oak at that time that Option 1 would apply. White Oak disagreed repeatedly, leaving Ameren forced to file White Oak's Facilities Service Agreement unexecuted with FERC. Under the proposed funding method, White Oak's network upgrades (actual cost $2,399,128) will cost $8,292,180 over 20 years under the ongoing rate. You can see Ameren's application to FERC here: White Oak FSA Application.
So why should White Oak receive a different result than the customers in Rail Splitter and Hoopeston? White Oak should be treated differently because, until now, it had no prior opportunity to complain to FERC about this method for funding network upgrades that we know to be discriminatory. Unlike the customers in Rail Splitter and Hoopeston, who waived their opportunity to complain and consequently needed FERC to undo contracts they'd agreed to, White Oak has never agreed to Option 1 funding--there is no contract to undo As a result, White Oak should now be afforded the chance to argue against Option 1 funding on the merits (see E.ON), rather than being hung up by procedural technicalities and the Mobile-Sierra doctrine.
If FERC were to rule in White Oak's favor, then the decision would help to restrict the application of this discriminatory method of funding network upgrades to a limited group of interconnection customers (i.e., those who expressly agreed to Option 1 in a contract) and to insulate those who are just now receiving notice of Option 1 funding from the absurd results that accompany it. But we'll need to wait and see if those at FERC who call balls and strikes see it the same way.
"Don't mess with Texas." Apparently the slogan even applies to liquidated damages clauses.
This morning, the Supreme Court of Texas issued a decision in a drawn-out fight between wind developer FPL Energy and the power marketer TXU Portfolio Management. The dispute originates from power purchase agreements (PPAs) in which FPL failed to deliver enough electricity and renewable energy credits (RECs) to cover its performance guaranty over a period of four years, in large part because of congestion and resulting curtailment orders by ERCOT. TXU initially brought suit for the shortfall, and FPL countered by claiming that the shortfalls were due to curtailments by ERCOT, and that TXU caused those curtailments to occur by failing to ensure that transmission capacity would be available away from the project delivery point. In any event, FPL argued that the liquidated damages for the shortfall amounted to an unenforceable penalty.
At the time of negotiating the PPAs, TXU and FPL agreed by contract that a shortfall in RECs would trigger liquidated damages in the amount of $50 per REC. There was no market for RECs at the time, and so the parties had settled on this damages amount by using the $50 per REC penalty that the Public Utility Commission of Texas could impose on utilities for not acquiring enough RECs. (The parties also agreed to an alternative price of twice the market value of RECs as determined by the Public Utilities Commission of Texas, if any such determination occurred.)
But today the Supreme Court of Texas ruled that the parties' agreed-upon liquidated damages provision amounts to an unenforceable penalty. Although the clause may have been a reasonable estimate of TXU's damages at the time of negotiation--particularly given that the clause mirrored the regulatory penalty for REC shortfalls--the provision failed to reflect actual damages at the time it was applied. The parties' powers of divination had failed them!
In the court's words: "When the liquidated damages provisions operate with no rational relationship to actual damages, thus rendering the provisions unreasonable in light of actual damages, they are unenforceable." In other words, it does not matter that the liquidated provision in the PPA was a reasonable estimate of damages at the time it was negotiated. Instead, what matters is whether the liquidated damages provision at the time it is applied reflects actual damages. As a result, a provision that was once reasonable became invalidated when market values later created a significant difference between the past estimate and actual damages.
To put this in a broader context, not all states approach a liquidated damages provision in this way. In its decision, the Supreme Court of Texas applied the "second-look" doctrine to the liquidated damages clause (despite seemingly starting toward a different doctrine), meaning that the court considered whether the liquidated damages provision was reasonable at the time it was negotiated, and also whether it is reasonable at the time it is applied. A "one-look" state considers only whether a liquidated damages clause was reasonable at the time it was negotiated. If FPL and TXU had chosen in the PPA to apply the laws of a "one-look" state, then the result may have had many differences--tens of millions of differences.
As to how FPL wound up in the shortfall position to begin with, FPL argued that TXU had failed in its contractual duty to provide transmission capacity to deliver electricity away from the delivery point. That failure resulted in higher than expected congestion and resulting curtailment orders from ERCOT. TXU countered that its transmission service obligations were limited to transmission for “Net Energy” - i.e. energy that was first delivered to the Delivery Point. The court agreed with TXU, holding that TXU’s transmission obligations arose only when the FPL-generated electricity actually reached the Delivery Point. The court reached this holding notwithstanding its recognition of FPL’s argument that transmission congestion and ERCOT's related curtailment orders had prevented electricity from reaching the delivery point in the first place.
You may read the court's opinion here: TXU v. FPL.
Converting a qualifying facility's legacy PURPA interconnection agreement to a FERC-jurisdictional agreement can be an effective way to bypass the numbing headache that often accompanies taking a new power generation project through the interconnection queue. One may even be able to throw in a repower and, voila!, you have a refreshed facility that can operate for decades more in broader bilateral power markets without having years of interconnection delay.
But there are ins-and-outs to these conversions, and today FERC addressed the question of whether a qualifying facility owner may necessarily convert the capacity that's stated in its PURPA interconnection agreement. For qualifying facility owners--it isn't the answer you wanted.
See FERC's order by following this link: CalWind Order.
For those companies owning generation on the Bonneville Power Administration system, mark your calendars for March 15, 2014. That's the day by which you must submit your facility displacement costs for Bonneville's implementation of its Oversupply Management Protocol (aka Environmental Redispatch) that provides compensation for certain generator curtailments. The failure to submit facility displacement costs will result in a displacement cost of $0.00 per MWh.
So begin registering your facility with Bonneville now at https://oversupply.accionpower.com so that you are prepared for when Bonneville begins accepting displacement cost information on February 28.
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.