Jason A. Johns

Jason A. Johns has no picture

Jason Johns is a partner in the Energy Development group. Hefocuses his practice on federal energy regulation, reliability issues,transmission, and power purchase agreements. Jason is also registered topractice before the U.S. Patent and Trademark Office and has assisted inauthoring patents for various chemical processes.


Articles By This Author

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.   

 

 

Negotiating a Liquidated Damages Clause in Texas? Get Out Your Crystal Ball.

"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.

Co-Authored by Jennifer Martin and Jason Johns.

Qualifying Facility Conversions - It's What All the Kids Are Talking About

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.

DEADLINE For Generators on Bonneville Power's System

 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.  

 

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.

FERC Performs an About-Face in Idaho

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.  

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.

 

 

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

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