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.

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

The Federal Energy Regulatory Commission ("FERC") is seeking comments from energy industry participants on regulatory reforms that address how FERC should regulate merchant transmission development and generator interconnection (or lead) lines. Specifically, FERC desires comments on how it should balance the requirements of open access transmission and the needs of project developers.

Merchant transmission and generator interconnection issues have caused a surge of contested FERC proceedings in recent years. In 2009, merchant transmission developers, for instance, were granted the ability to place transmission capacity with anchor tenants prior to making capacity available through an open season. The anchor tenant model was a significant shift in merchant transmission regulation, but, to date, merchant transmission developers have struggled to maintain meaningful anchor tenant arrangements. As a result, more recent filings at FERC have pushed the boundaries of the anchor tenant model, and FERC now seeks to determine through public comment how its open access policies could be further changed to incentivize merchant transmission development.

Generator interconnection lines have also been a popular subject at FERC of late—specifically whether and how interconnection line owners should be granted priority rights to interconnection capacity. This issue is particularly relevant for renewable energy developers who are planning to build generation projects in phases and will rely on having interconnection capacity available to serve later phases when they come online. To maintain priority over competing interconnection requests, FERC has asked generation developers to show they have established milestones for developing the generation phases that seek priority (and to demonstrate progress toward meeting those milestones). Such filings are generally confidential, and thus interconnection line owners from the outside looking in have not been given much insight into what is required to establish priority. FERC's precedent on the issue has also created dissimilar treatment of interconnection owners who are affiliated with open access transmission providers.

On March 15, 2011, FERC staff held a technical conference where the invited speakers shared a wide range of opinions on these issues. With respect to merchant transmission, speakers supported (i) creating a new section to the Open Access Transmission Tariff ("OATT") that would specify the rules for developing merchant transmission and the ancillary services obligations of those developers, (ii) placing AC merchant lines under existing incumbent transmission provider OATTs, (iii) allowing more incentives for anchor tenants, and (iv) having FERC back away from regulating these projects in their early stages. Those who spoke about priority to interconnection capacity shared opinions that included (x) requiring interconnection developers to give public notice of their development intentions and allow others to bid on capacity (a "speak now or forever hold your peace" approach), (y) requiring all interconnection owners to develop and maintain an "OATT light"—a pared down version of the full OATT, and (z) advocating for less regulation of interconnection lines altogether. FERC staff also questioned whether and how FERC should regulate transmission service over interconnection facilities that are shared or jointly owned (e.g., through a Joint Ownership Agreement, Shared Facilities Agreement, or Common Facilities Agreement) directly by generation developers, or indirectly through an affiliate that owns and operates an interconnection line.

Written comments on these issues are due to FERC no later than April 21, 2011.

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

To continue reading, click here.

1. FERC opens a rulemaking on variable energy resources.
2. FERC extends the comment deadline in the appeals by wind farms registered for transmission reliability functions.
3. FERC denies a petition to protect priority to interconnection capacity rights.

FERC Opens Rulemaking on Intra-Hour Scheduling, Forecasting Requirements, and Integration Services for Variable Energy Resources

The Federal Energy Regulatory Commission (FERC) proposed amending its pro forma open access transmission tariff to correct practices that are unduly discriminate against variable energy resources (VERs) such as wind and solar energy generators. In the November 18, 2010 Notice of Proposed Rulemaking, FERC outlines measures that, if adopted, will (a) require transmission providers to offer transmission service that can be scheduled on 15-minute intervals, (b) require interconnection customers that operate VERs to provide site-specific forecasting and meteorological data to transmission providers that are deploying and/or developing power production forecasting processes, and (c) add a new rate schedule for generation regulation (i.e., integration) services. The proposed rulemaking is the first to come out of the January 2010 Notice of Inquiry on the Integration of VERs—a docket that received well over 100 comments from industry stakeholders.

Read more on the Notice of Proposed Rulemaking on VERs here.

FERC Extends Comment Period in Wind Farms’ Appeal of NERC Decision to Uphold Registration as Transmission Owners/Operators

FERC has extended the comment deadline in an appeal by two wind farms that were registered for Transmission Owner and Transmission Operator reliability functions, a potentially costly registration for the wind farms that was affirmed by the North American Electric Reliability Corporation (NERC) in October. The NERC decision and its supporting analysis, if affirmed by FERC, have the potential to broadly apply to many generation developers, owners, and operators.

Read more on the wind farms’ appeal here.

FERC Denies Puget Sound Energy's Request to Protect Interconnection Capacity Rights

In June of this year, Puget Sound Energy (Puget) filed a petition with FERC for a declaratory order to protect its rights to 1,250 MW of interconnection capacity that would eventually serve the Lower Snake River Project wind farm. Puget argued that constructing the entire interconnection capacity needed for the full project upfront was financially efficient and environmentally responsible, and that other developers should not be able to claim rights to the capacity. On November 18, 2010, FERC distinguished the petition from an earlier decision in Milford and denied Puget’s request to establish its priority rights to the interconnection capacity. FERC reasoned that the capacity over Puget’s generator lead lines must be governed by its open access transmission tariff. FERC also found that any interconnection capacity that is not appropriately reserved for Puget’s native load must be made available to other open access customers.

Read more on the FERC decision denying Puget’s request to protect its interconnection capacity rights here.

If you have questions about the issues addressed in this report, please contact:

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

The PUC included six cost categories in the wind SAR:  capital costs; fixed and variable O&M costs, transmission costs; tax credits; wind integration; and forecasting costs.  The PUC assumed transmission costs of $1.90/kw-month, production tax credits at $0.021/kWh, a $0.00 REC premium, and wind integration at $6.50/MWh.  With those inputs and others, the PUC arrived at 20-year levelized wind rates for a 2010 project as follows:

The PUC proposed that where the Wind SAR is higher than the Gas SAR, a wind developer may choose whether to sell power at the wind or gas rate.  If the wind developer opts for the latter, it retains ownership of RECs.  If the wind developer opts for the former, RECs go to the utility.  However, when the Gas SAR is higher than the wind SAR, wind developers would only be eligible for the wind SAR, meaning that the utility would automatically receive RECs under a PPA.  Non-wind projects would be entitled to the gas SAR when the gas rate is higher, and RECs would remain with developers.

The PUC is accepting written comments on the straw man proposal until November 23, 2010.

2012-2013 - 3%

2014-2015 - 6%

2017-2018 - 9%

2019-2020 - 12%

2021 - 2039 -15%

Renewable resources that can be used toward compliance will include wind, solar, ocean, geothermal, biomass, landfill gas, incremental hydropower, hydrokinetic, new hydropower at existing dams, and waste-to-energy.  For utilities that are unable to meet their RES targets, the bill proposes to charge a compliance payment at a rate of 2.1 cents per kilowatt hour, with such amounts then being used for renewable energy development or to offset consumers' bills.

A first step, yes.  But a small one.

Follow the link to learn more:  

Both papers focus on the challenge of developing U.S. transmission infrastructure and capacity, particularly in the West.  In The Way Forward:  Why Transmission Right Sizing and Federal Bridge Financing Hold the Key to Western Renewable Resource Development, the authors (Marcus Wood, Pam Jacklin, and myself) consider economy-of-scale and environmental impact concepts and their application to the sizing of transmission facilities.  The authors also argue for a significant overhaul of current financing and cost recovery mechanisms in order to provide a pathway for greater development of renewable energy resources.  You can download a copy of The Way Forward by clicking here.

In Uncork That Transmission Bottleneck:  A Legislative and Technological Roadmap for Tapping the West's Vast Renewable Energy Resources, the authors examine broader issues affecting renewable energy development.  This white paper proposes a number of policy goals that could drive transmission development in the West and on a national level.  You can download a copy of Uncork That Transmission Bottleneck by clicking here.

 We hope that you enjoy these papers.

With a swift 13-page order today, FERC rejected Puget Sound Energy’s proposed wind integration rate, stating that the rate was not shown to be “just and reasonable” under section 205 of the Federal Power Act.  “Changing system conditions, such as an increasing amount of wind generation described by Puget, present unique challenges that may require novel solutions.  However, such solutions must fit the problems they are intended to solve, and the Commission must ensure that ratepayers are protected from rate proposals—such as the one proposed by Puget here—that are not shown to be related to the actual, demonstrable costs incurred in providing service.” 

To determine the rate, Puget had used a proxy rate calculated using hypothetical capacity costs from a hypothetical generator.  Puget chose its proxy from a group of five commercially available peaking units in the area.  FERC stated that although it will allow for the recovery of legitimate and verifiable opportunity costs,  Puget’s proposed rate was not a “reasonably accurate representation of the opportunity costs Puget incurs” in providing wind integration service.  Because FERC cannot permit Puget to over-recover its costs in providing the service, the rate was rejected.  Puget will undoubtedly be back to FERC with a rate that attempts to be consistent with FERC’s order.

Click here to read the order.

Details regarding NV Energy's Spring 2010 RFP can be found by clicking here.

Responses are due May 28, 2010.  Follow the link for the solicitation materials: www.scppa.org/Downloads/RFP/Renewable_Energy_Projects_052810.pdf

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

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

To read more about today's U.S. Supreme Court decision, click here.

1.  Dayton Power and Light Company is seeking to acquire up to 313,000,000 kWh of eligible RECs by 2013 in order to meet Ohio's RPS requirements.  Deadline for submissions is August 7, 2009.  Click here for more information.

2.  The Western Area Power Administration is seeking RECs on behalf of certain WAPA regional offices and federal agencies.  Deadline for submissions is August 7, 2009.  Click here for more information. 

3.  Southern California Edison seeks to acquire energy from eligible renewable resources.  Click here for more information.

4.  AEP Ohio is looking to acquire 30,000,000 kWh of eligible RECs to use toward compliance with Ohio's RPS requirements.  Interested parties must submit a Notice of Intent to Bid by July 31, 2009.  Click here for more information.  AEP Ohio also has an active RFP for renewable energy, which you can learn about here.

5.  Puget Sound Energy seeks to acquire 30,000,000 kWh of eligible RECs.  Interested parties must submit a Notice of Intent to Bid by July 31, 2009.

6.  Bryan Texas Utilities hopes to acquire up to 10 MW of utility-scale solar energy and the associated RECs generated within ERCOT.  The deadline for submissions is August 24, 2009.

7.  Seattle City Light is looking to acquire 50 MW of new renewable resources to meet Washington RPS requirements.  Submission deadline is August 28, 2009.  You can find more information here.

8.  The US General Services Administration seeks to acquire 40,000,000 kWh per year of RECs for the Architect of the Capitol and other federal agencies.  Submission deadline is September 1, 2009.  You can find more information here.

In addition, FERC established an interim rate policy that, once certain showings are made, will provide public utilities with the ability to recover the costs of FERC-jurisdictional smart grid technologies and the legacy systems being replaced.  The interim rate policy also allows public utilities to apply accelerated depreciation to smart grid deployments and recover the full cost of smart grid technologies that are later abandoned or made obsolete.  Public utilities seeking incentive rate treatment must file an appropriate application with FERC before it adopts smart grid interoperability standards.

For more information on FERC's Policy Statement, click here for our recently-released client alert.

If you would like to read the Policy Statement itself, click here.

• Power Purchase Agreement (PPA).  Respondents are asked to propose a 10, 15, or 20-year PPA for capacity and/or energy, but SDG&E will nevertheless consider proposals with shorter or longer durations.  Eligible Resources must be delivered to a point within California and must be begin deliveries sometime between 2010 and 2013.
• PPA with Buyout.  Respondents offering PPAs may also submit an option price that SDG&E may exercise to purchase the resource as well as associated environmental attributes, land rights, permits, and other licenses upon conclusion of the PPA term.  This alternative is limited to resources located in San Diego County, parts of Orange County within SDG&E's service territory, or Imperial Valley areas.  Like respondents offering under the PPA alternative, respondents interested in offering resources under the PPA with Buyout alternative must begin delivering energy and/or capacity between 2010 and 2013.
• Turnkey Facilities.  Respondents to the RFO may also propose to develop and construct a new renewable energy generation facility that SDG&E will acquire.  SDG&E is proposing the same locational requirements that apply to PPA with Buyout projects.

A limitation that applies to all respondents is that resources located in SDG&E's service territory must be no smaller than 1.5 MW, and resources outside of SDG&E's service territory must be no smaller than 5 MW.

This RFO may be a great opportunity to transact with SDG&E as it endeavors to comply with California's ever-increasing RPS standards.  SDG&E will hold two pre-bid conferences:  one in San Diego on August 5, 2009, and the other in El Centro on August 12, 2009. Those interested in attending a pre-bid conference should register by July 31. 

For more information, click here:  SDG&E 2009 RFO Info

FERC's approved the following (non-exhaustive) key incentives that reduce GPE's exposure to risk in moving the project forward.

Abandoned Plant.  FERC granted GPE's request to recover prudently incurred expenses if the project is abandoned for reasons outside of GPE's control.  FERC stated that the recovery of abadonment costs is a means for encouraging transmission development, reducing the risk that GPE's investors may lose their entire investment. 

Regulatory Asset.  FERC will allow GPE to create initial and subsequent vintage regulatory assets in order to defer pre-construction, development, and start-up costs until GPE has customers from which it may later recover those costs.  Such cost deferral will also help GPE attract financiers.

Construction Work in Progress.  FERC approved GPE's request to include 100 percent of construction work in progress in its revenue requirement, allowing GPE to service its debt and reduce borrowing over the project's development--something that would otherwise be difficult for a $10-12 billion project with a 2020 in-service date.

The incentives granted to GPE, as well as other recent changes to FERC's transmission policies, show that the agency is becoming increasingly serious about spurring transmission development forward.  If we are to reach the 62 GW of wind currently in the Midwest ISO interconnection queue, as well as other renewable resources elsewhere, transmission developers will need creative regulatory solutions to help attract financiers and gain firm commitments from generation developers.  FERC continues to take positive steps forward.

For more information about the viability of superconducting transmission lines, look for American Superconductor's White Paper in the near future.