California Energy Law Blog - Renewable Energy Lawyer & Clean Electricity Attorney

This blog post comes from my DC colleague Margaret Claybour. Generation developers on the West Coast should take special note as the FERC orders described in this blog all involve facilities out West.

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When an unwary generation developer builds a tie-line to the nearest transmission line, it might assume that the use of that line can be wholly dedicated to moving power from its generation facility to the grid.  But that assumption would be incorrect.  With the stroke of a pen (or a computer keystroke), a third-party can transform the generation developer into a transmission provider simply by requesting interconnection to that generation tie line.  When that happens, the generation developer instantaneously becomes subject to FERC’s open access rules, the same rules usually reserved for transmission-owning public utilities, including the requirement to file an open access transmission tariff (OATT).

On April 19, FERC issued a Notice of Inquiry (NOI) asking for help in applying this policy.  Developers and others should consider speaking up.

FERC’s Current Policy

Under FERC’s current priority rights policy, there are three instances in which the owner of generator interconnection facilities can reserve priority rights to capacity on its line:  (i) for its “existing use” at the time of a third party request for service; (ii) for future use based on “specific, pre-existing generator expansion plans with milestones for construction of generation facilities” for which the owner can demonstrate that it has made “material progress toward meeting those milestones” that pre-dates a third party request for service; and (iii) for use by an affiliate that can meet the “specific plans and milestones” standard and to whom ownership of the interconnection facilities will be transferred.  FERC’s first articulated the “specific plans and milestones” standard in 2006 in its Aero Energy, LLC order.  Arguably, it wasn’t until 2009, in Milford Wind Corridor, LLC, that FERC provided some clarification of how a developer can satisfy the standard.  Even so, as we’ve seen in Terra-Gen Dixie Valley, LLC, what qualifies as “specific plans and milestones” still isn’t clear.  FERC’s priority rights policy borders on a “we’ll know it when we see it” approach, which does not leave a generator developer with much certainty.

Even if a generation tie line owner is able to secure priority rights for itself or its affiliates on its interconnection facilities, the OATT filing requirement still looms.  Under FERC’s current policy, a “valid” request to interconnect from an unaffiliated third party triggers the requirement to file a pro forma OATT within 60 days of the request, whether or not priority rights exist.  The generator is thereby forced to divert staff and financial resources to develop and maintain an OATT.  And while FERC typically grants waiver of several provisions in the pro forma that clearly do not apply to transmission service on a generation tie line, for example, network transmission service, the generator’s OATT must include potentially onerous provisions, such as transmission planning and calculations for available transfer capabilities.

As my colleague Brian Gish discussed in his advisory on the subject: generation tie line owners also can be required to comply with NERC’s mandatory electric reliability standards for transmission facilities, in addition to the bevy of reliability obligations required for Generator Owners and Generator Operators.  This, too, can tax a generator’s financial and personnel resources.

What FERC’s Looking for in its NOI

Through the NOI process, FERC is seeking comments on “alternative approaches to govern third-party requests for service and priority rights.”  Considerations on the table include: use of a modified OATT, including a safe harbor period during which a third party may not submit interconnection requests to the generation tie owner; and in lieu of the OATT framework, use of the large generator interconnection procedures, permitting the parties to mutually agree to use of and compensation for the facilities.

Notably missing from the NOI is discussion of the NERC implications of a generation tie line being used to provide transmission service.  We’ll have to await the outcome of NERC’s ongoing Project 2010-07, which involves proposed changes to generator requirements at the interface with the transmission grid, to get, hopefully, some clarity regarding the reliability obligations of generation owners and generation operators.  Stay tuned.

NOI comments are due June 11, 2012.

Commissioner Simon and Administrative Law Judge Kenney presided over a prehearing conference in the Commission’s fire safety proceeding (R.08-11-005) today.  The usual players were in attendance– the electric utilities, the communication utilities, consumer groups, environmental groups, and a few new players from the fire safety community (CalFIRE and LA Fire).

Today’s topic was to determine the scope of Phase 3.  Items that will certainly be included in Phase 3:

1) the detail and amount of reporting by the electric utilities on fires or other events that occur on their power lines;

2) revising the construction and strength requirements for power-line and aerial communication facilities.

The big question today was on what sort of maps should be used/created to assess fire risk and to determine inspection cycles.  Another important question that will be determined by the Commissioner’s scoping memorandum that will be issued soon is what uses the Commission envisions coming from the map.

Commissioner Simon hinted at the hearing that he saw a broader vision for the use of the maps beyond just identifying fire risk.  He appears to be leaning towards developing maps that identify the amount of available biomass in certain areas that could then be used to site potential biomass facilities around the state– an interesting idea, but not exactly what the majority of the parties at the hearing envisioned coming out of this proceeding or being within the scope of Phase 3.

Should be an interesting proceeding that may have ramifications not only in California, but in other states and countries where fire safety is of paramount importance.

Important news from the Air Resources Board.

Mary Nichols, Chair of the California Air Resources Board, announced at a state Senate panel yesterday that the first auction of greenhouse gas emission allowances would be delayed by 3 months and held in November.  This makes sense as no protocols regarding how the auction would be conducted have been released as of yet.

Mary Nichols did state that the California Air Resources Board does intend to hold a “practice auction” in August.  The practice auction in August is meant to give covered entities (companies that actually will have to purchase these greenhouse gas allowances) an opportunity to see how the system will actually work.

Since the compliance obligations do not actually go into effect until 2013, pushing back the first actual auction should not cause any real delays to the implementation of the cap and trade program overall.  But the need to delay the initial auction does speak to the difficulties of implementing the cap and trade program.

Given the complexity in the program, it likely makes sense for covered entities to participate in the practice round and get their feet wet.

The California Public Utilities Commission released a much awaited proposed decision  on March 20th regarding metrics to measure the deployment of the smart grid in the PG&E, SCE, and SDG&E service territories.

The consensus metrics can be found in Attachment A to the proposed decision.   The consensus consists of 19 metrics that the utilities will report on as part of their annual reports.

Specifically, the metrics are related to Customer/AMI metrics; plug-in electric vehicle metrics; storage metrics; and grid operations metrics.

The Decision does establish 4 technical groups to address

1) updates or revisions to the metrics adopted herein, if needed;
2) the creation of metrics related to cyber-security;
3) the creation of metrics related to environmental
benefits; and,
4) the creation of broad goals to focus all stakeholders toward a
common vision.

Opening Comments on the proposed decision are due Monday April 9.  Reply comments on the proposed decision are due Monday, April 16.

PG&E filed an application at the California Public Utilities Commission requesting $19.4 million to fund the project to provide third parties with access to a customers’ electricity usage data (when authorized by the customer) as part of its Customer Data Access Project.

Following the Commissioner’s earlier decision regarding  privacy and security restrictions on customer data, PG&E proposes a customer verification process that will require affirmative confirmation from customers authorizing third parties access to their electricity usage data, as well as specific specifications regarding the scope and duration of such third party access.

The Customer Data Access Project is obviously an important step in the quest for a smart grid in California, and another set of costs incurred by customers in order to make the smart grid a reality, so all those companies seeking to use energy data in their products should pay close attention to how PG&E’s application moves forward.