The regulation of transmission is changing due to the need to facilitate grid access for remote generation, which is often renewable power that can be developed best in areas far away from load centers. Separately, but not always independently of this need, regulatory authorities have wanted to open up development possibilities for transmission projects to entities other than incumbent public utilities. On July 21, 2011, the Federal Energy Regulatory Commission (FERC) issued Order No. 1000, a landmark order adopting reforms to its electric transmission planning and cost allocation requirements for public utility transmission providers subject to FERC authority.1 The fundamental purpose of the new rule is to make it easier for remote generation facilities to access the grid and at the same time facilitate the development of transmission projects. Texas, however, has developed its own separate transmission policies applicable to its intrastate grid, ERCOT. The purpose of this article is to explore what effect FERC Order No. 1000 has had in opening up transmission development to competition and compare that effect to the Texas experience.
November 01, 2016 Feature
Transmission Grid Expansion—Where Are We Now?
By Kerry McGrath and James A. Nortey II
What Does FERC Order No. 1000 Require?
Order No. 1000 requires transmission providers to (1) eliminate provisions of their respective Open Access Transmission Tariffs that grant a federal right of first refusal (ROFR) to transmission facilities, (2) participate in regional transmission planning processes to evaluate regional solutions, (3) improve coordination across regional transmission planning processes by developing procedures for joint evaluation and sharing of information regarding needs of transmission planning regions and respective solutions, and (4) establish regional and interregional cost allocation methodologies. In particular, Order No. 1000 creates three key reforms regarding the issues of the removal of the federal ROFR, transmission planning, and cost allocation.
Federal ROFR Requirements
Previously, utilities established a federal ROFR in their tariffs and agreements with incumbent transmission developers. Traditionally, incumbent transmission owners took a proactive role in transmission planning by presenting Independent System Operators (ISOs) or Regional Transmission Operators (RTOs) with potential projects. Under this approach, ISOs and RTOs were mostly reactive to the projects presented and evaluated them on an ad hoc basis.
FERC concluded that allowing federal ROFRs to remain in FERC-jurisdictional tariffs and agreements could undermine the consideration of potential transmission solutions proposed at the regional level because it is not in the economic self-interest of incumbent transmission providers to permit new entrants to develop transmission facilities, even if their proposals would result in a more efficient or cost-effective solution to the region’s needs.2
Under Order No. 1000, transmission providers are required to remove from FERC-jurisdictional tariffs and agreements any provisions that give incumbent transmission providers a federal ROFR to construct new regional transmission facilities.3
As a result, transmission projects that have traditionally been assigned based upon geographic location and service territory are now open to competition. Incumbent utilities will no longer maintain the federal ROFR to build, own, and operate large-scale transmission projects that are located within their service territory.
Regional and Interregional Transmission Planning Requirements
Additionally, Order No. 1000 requires all public utility transmission providers to participate in a regional transmission planning process that produces a regional plan for the development of new, regional transmission facilities and that includes procedures to identify transmission needs driven by public policy requirements.4
All regional planning must provide opportunities for participation by interested stakeholders and must take into account “public policy requirements.”5 Public policy requirements refer to efforts that “will support the development of those transmission facilities identified by each transmission planning region as necessary to satisfy reliability standards, reduce congestion, and allow for consideration of transmission needs driven by public policy requirements established by state or federal laws or regulations.”6 This would also include all statutes and regulations promulgated by any state or federal authority.7
Under Order No. 1000, adjacent planning regions also must establish procedures to share planning data and identify more efficient interregional solutions to transmission needs.8 Adjoining regions must coordinate the planning of interregional facilities, i.e., facilities that would be located in two or more planning regions, but are not required to create a formal interregional plan.9
Cost Allocation Requirements
FERC Order No. 1000 mandates coordination and collaboration on allocation of costs for transmission projects. The new rules require each transmission provider to participate in a regional transmission planning process that has (1) a regional cost allocation method for the cost of new transmission facilities selected in a regional transmission plan10 and (2) an interregional cost allocation method for the cost of new transmission facilities that are located in two neighboring transmission planning regions.11 Furthermore, Order No. 1000 requires that each cost allocation method satisfy six cost allocation principles for a regional or interregional transmission facility.12 Acknowledging that each transmission-planning region has unique characteristics, FERC accords transmission planning regions flexibility to tailor regional and interregional transmission planning and cost allocation processes to accommodate their respective differences.13
Has FERC Order No. 1000 Worked?
Introducing Competition
ISOs and RTOs are responsible for monitoring and coordinating the operation of electrical power systems within their respective territories. These ISOs and RTOs were required to make changes to their respective tariffs and submit proof to demonstrate compliance with Order No. 1000. These transmission-planning regions, which went through several iterations of FERC compliance filings before receiving final approval, are at various stages of implementing their processes.
Order No. 1000 introduced and enhanced competition efforts in the transmission planning process. As a result of FERC’s reforms, two different competitive project selection methods have emerged. Under the competitive bidding model, transmission planners identify the projects they want and solicit bids from developers. Usually, cost is the deciding factor under a competitive bidding model. The California Independent System Operator (CAISO) has adopted this model.
Under the sponsorship model, transmission planners identify transmission needs and allow developers to propose solutions. Through this model, developers have more latitude to use their creativity to identify potential solutions. PJM, New England Independent System Operator (ISO-NE), and New York Independent System Operator (NYISO) have adopted the sponsorship model. There is an open question regarding whether the long-term savings from selecting the right project under the sponsorship model outweigh the short-term savings from picking the cheapest developer in a bid-based model. For that reason, the Midwest Independent System Operator (MISO) and Southwest Power Pool (SPP) have adopted a hybrid model that is weighted toward cost but awards points for various project characteristics, such as design, assurance of delivery, project developer team, and so forth.
Transmission Build-Out Among RTOs and ISOs
The post-Order No. 1000 transmission build out has seen mixed results—with fits and starts. Currently, no transmission projects have been constructed as a direct result of FERC’s competitive reforms.
In January 2016, MISO issued a formal request for proposal for its first competitive transmission project, the Duff-Coleman 345-kV project in Southern Indiana and Kentucky. The project is expected to be in-service on January 1, 2021. MISO recently completed its initial review of all submitted proposals for purposes of completeness and will begin evaluating the proposals based on the criteria set forth in the MISO tariff, such as specificity, risk mitigation, and cost, among others. MISO planned to announce a selected developer proposal by December 30, 2016.
In April 2016, SPP completed its first competitive solicitation for a 22.6-mile 115-kV line in southwest Kansas. But after a drop in forecasted loads from oil and gas exploration (173 MW to 25 MW), the line was canceled.
In 2015, PJM approved a proposal to build the Artificial Island project, a 230-kV transmission line under the Delaware River. However, the project became increasingly controversial due to escalating costs and was recently canceled.
CAISO has not issued a competitive solicitation since 2014. Moreover, neither NYISO nor ISO-NE has yet to award any Order No. 1000 projects.
Transmission entities have undergone coordinated planning efforts, such as joint conferences and transmission studies, in order to implement Order No. 1000’s interregional planning requirements. The aim of these coordinated planning efforts is to enhance the widespread reliability and efficiency of the interregional electric power system. However, compared to the development of regional planning efforts, interregional planning efforts have moved at a glacial pace.
How Has Transmission Expanded in Texas?
With the distinct advantage of a single jurisdiction and regulator, the portion of Texas within the Electric Reliability Council of Texas (ERCOT) has successfully built substantial transmission to serve renewable generation through the competitive renewable energy zone (CREZ) program. CREZ was a nine-year effort that began with a directive from the Texas Legislature in 2005 and culminated in 2013 with the completion of over 2,000 miles of 345-kV transmission capable of interconnecting over 18,000 MW of renewable generation. Propelled by the CREZ program, Texas has far surpassed all other states and most countries in installed renewable generation.
CREZ began with Senate Bill 20, enacted by the Texas Legislature in 2005. The legislation directed the Public Utility Commission of Texas (Texas PUC) to designate CREZ zones and develop a plan to construct transmission to deliver renewable energy from those zones to customers.
Following enactment of SB 20, the Texas PUC adopted Substantive Rule 25.174,14 which directed ERCOT to obtain a study of wind energy production potential in Texas, and then contemplated a series of contested proceedings to designate the CREZ zones, approve a transmission plan to connect those zones to customer load, and select the transmission providers to construct that plan. The rule also required that renewable energy developers provide financial commitments that they would connect with the CREZ lines once completed; further development of the lines was contingent on sufficient financial commitments.
The Texas PUC implemented the CREZ plan primarily through two contested case proceedings, each of which attracted dozens of participants. In the first proceeding, Docket No. 33672, the Texas PUC considered the study of wind energy potential in Texas conducted for ERCOT and selected six zones in West Texas and the Panhandle to be served by the CREZ transmission facilities.15 After selecting the CREZ zones to be served, the Texas PUC directed ERCOT to develop transmission plans to connect those zones to ERCOT load, generally located along the Interstate 35 corridor from Dallas/Ft. Worth south to San Antonio, at four levels of service ranging from 10,000 MW to over 23,000 MW.
In Docket No. 33672, the Texas PUC also considered the transmission plans proposed by ERCOT to serve the CREZ zones. After a contested hearing, the Texas PUC selected ERCOT’s “Scenario 2,” designed to deliver 18,456 MW of renewable energy from the designated CREZ zones to load.16 The Texas PUC’s order identified numerous transmission projects to be built and designated some of them as priority projects necessary to deliver existing constrained generation. The Texas PUC also instructed parties wishing to interconnect the Panhandle CREZ zones to obtain a FERC order disclaiming jurisdiction over ERCOT, and it established a subsequent case to select transmission providers to construct the CREZ lines.
Docket No. 35665 was the subsequent case to select CREZ transmission providers.17 Most of the incumbent investor-owned utilities in ERCOT, several public power utilities, and five proposed new entrants filed proposals to build portions of the transmission plan. During the course of the case, various applicants filed joint proposals to coordinate the division of facilities with each other. After a vigorous hearing, the Texas PUC rejected all the joint proposals and developed its own plan to allocate the facilities among ten incumbents and three new entrants.18
Having designated the CREZ zones, approved the transmission improvements to deliver the renewable energy from those zones to load, and selected the transmission providers to build the improvements, the Texas PUC then presided over approximately 30 certificate of convenience and necessity (CCN) cases over the next two years to route the transmission lines, each on a statutory 180-day schedule.19 Following completion of these cases, the lines were constructed and energized, at the Texas PUC’s direction, by the end of 2013.
In less than a decade, the Texas PUC oversaw the planning, design, and construction of over 2,000 miles of high-voltage transmission lines and associated facilities to deliver renewable energy from remote areas of the state to load centers. The result has been an explosion of installed renewable generation, mostly wind, which far surpasses all other states and most countries. The same transmission infrastructure is poised to deliver solar energy, which tends to produce at different times than wind, in the future.
There were several keys to Texas’s success. Most notably, ERCOT is subject almost exclusively to the jurisdiction of the Texas PUC, allowing one regulator to oversee and drive the entire CREZ process from inception to completion. And the Texas PUC did indeed drive the process, vigorously and aggressively, including approving a CREZ transmission plan that far exceeded the renewable energy goal established by the legislature.
The same unified jurisdiction that allowed the Texas PUC to completely manage the CREZ build-out has also enabled the ERCOT grid to operate under a straightforward, non-litigious cost allocation method for transmission investment. Since the market was restructured around 2000, ERCOT has operated under a “postage stamp” method of transmission cost recovery under which all transmission costs are rolled into a system-wide cost of service and allocated to load-serving entities based on their share of system peak demand.20 This approach eliminates cost allocation disputes and provides a simple, prompt method for recovery of transmission investment that has proven attractive to investors, as evidenced by the competition to be awarded CREZ projects.
Post-Order No. 1000 Developments: Five Years Later
In June 2016, FERC held a commissioner-led technical conference on Order No. 1000’s performance regarding competitive transmission development. Participants were invited to share comments on the impacts of the order and whether changes were needed. Some stakeholders suggested it was time to completely overhaul Order No. 1000, while others believed it was too early to tell if changes would be helpful. However, it was clear from virtually all participants that the project evaluation decision-making process needs to be more transparent.
In Order No. 1000, FERC tried to provide broad principles that would boost competitive efforts while giving transmission planners enough flexibility to tailor solutions to their region’s needs. However, developers are concerned that given all of the time and money invested in a proposal, transmission planners may have too much discretionary power and a greater level of specificity should be required in the respective tariffs. Additionally, developers would like to see publicly available data for submitted proposals regarding costs, proposal details, and why certain proposals were selected or rejected. At the same time, transmission planners are concerned about potential complaints and litigation from developers that were not selected.
Regarding interregional planning, there seemed to be a general consensus that although a great deal of progress has been made under Order No. 1000, more time is needed to realize the true potential of interregional planning. Transmission providers need more time to align practices and procedures among regions that historically had different approaches to transmission planning.
FERC invited stakeholders to file post-technical conference comments regarding cost containment, transparency, the need for standardization versus flexibility, transmission incentives, interregional transmission planning, and methodologies for gauging the impact of Order No. 1000. While it is entirely possible that FERC may revisit its reforms, it is clear that the Commission will remain engaged on the issue of facilitating additional competition for transmission infrastructure.
Conclusion
The electric industry is going through big changes in how it generates and delivers power. A robust transmission network is necessary to support those changes. FERC Order No. 1000 sought to ensure that new transmission is cost-effective by opening up transmission development to competition. While some progress has been made, all regions of the country have their own challenges with implementation of Order No. 1000. Although ERCOT in Texas is not subject to FERC jurisdiction, it may be useful to look at its experience as a more mature market for competitive transmission.
Endnotes
1. Transmission Planning & Cost Allocation by Transmission Owning & Operating Public Utilities, 136 FERC ¶ 61051 (FERC July 21, 2011) (Order No. 1000), order on reh’g, 139 FERC ¶ 61132 (FERC May 17, 2012) (Order No. 1000-A), order on reh’g, 141 FERC ¶ 61044 (FERC Oct. 18, 2012) (Order No. 1000-B).
2. Order No. 1000 ¶ 256.
3. Order No. 1000 ¶ 253.
4. Order No. 1000 ¶¶ 68, 146.
5. Order No. 1000 ¶ 150, 203.
6. Order No. 1000 ¶ 2.
7. Order No. 1000 ¶ 2.
8. Order No. 1000 ¶ 368.
9. Order No. 1000 ¶ 475.
10. Order No. 1000 ¶ 558.
11. Order No. 1000 ¶ 578.
12. Order No. 1000 ¶ 603.
13. Order No. 1000 ¶ 604.
14. 16 Tex. Admin. Code § 25.174.
15. Commission Staff’s Petition for Designation of Competitive Renewable Energy Zones, Docket No. 33672, Interim Order on Reconsideration (Nov. 6, 2007).
16. Docket No. 33672, Order on Rehearing (Oct. 7, 2008).
17. Commission Staff’s Petition for the Selection of Entities Responsible for Transmission Improvements Necessary to Deliver Renewable Energy from Competitive Renewable Energy Zones, Docket No. 35665, Order on Rehearing (May 15, 2009); modified on remand, Docket No. 37902, Final Order on Remand (Mar. 30, 2010).
18. Although not clearly contemplated by the initial CREZ legislation, the Texas PUC’s selection of new entrants to build a portion of the CREZ facilities effectively created three new transmission-only utilities in ERCOT.
19. See PUC Docket Nos. 36801 and 36802, sequencing the CREZ CCN cases.
20. See 16 Tex. Admin. Code § 25.192.