Subscriber Login


North America's Tryst with Competitive Bidding: Order 1000 brings paradigm shift [free access]

February 3, 2016

Competitive bidding in transmission is slowly gathering momentum in North America following the implementation of Order 1000, passed by the Federal Energy Regulatory Commission (FERC) in 2011. The landmark regulation aims to find the best solution to effectively address the new transmission investment needs, which are expected to be over USD125 billion by 2025.


Order 1000 aims to promote competition in the regional transmission planning processes to support efficient and cost-effective transmission development. It requires a non-discriminatory regional process to be put in place for transmission project evaluation and selection. This is largely facilitated by the provision that eliminates the federal right of first refusal (ROFR) of incumbent transmission providers with respect to transmission facilities which are part of the regional transmission plan for purposes of cost allocation. Further, Order 1000 requires public utility transmission providers to revise their Open Access Transmission Tariffs (OATT) to establish qualification criteria to determine if an entity is eligible to propose a transmission project for selection in the regional transmission plan for cost allocation; identify information a prospective transmission developer must submit in support of a transmission project; and describe a transparent and non-discriminatory process for evaluating proposals, among other things. A competitive bidding process is one of the recommended methods to comply with the requirements of Order 1000.


To be sure, several non-incumbent business models have emerged in the last few years, which include specific transmission partnerships with investment-owned utilities, public-private partnerships, independent transmission companies, merchant transmission, transmission bundled with renewables, and transmission only subsidiaries. The new rules shall provide a further boost to competition in the industry.


The general focus of competition thus far has been on regional projects at higher voltages. Broadly, there are two approaches to implementing Order 1000—pure competitive solicitations or tenders, and a hybrid process. In the case of the former, the Independent System Operators (ISOs)/Regional Transmission Organisations (RTOs) identify transmission projects themselves and bid them out. In the case of the hybrid process, as part of the comprehensive planning process, ISOs/RTOs identify a range of transmission issues or needs for which prospective developers may propose specific projects to solve the problem. After evaluation, an initial solution is identified and a further solicitation process is carried out to ensure that the selected solution is the best in terms of the cost and benefits associated with it.


The first approach has been adopted by California Independent System Operator Corporation (CAISO), Electric Reliability Council of Texas (ERCOT), Alberta ISO, Midwest ISO (MISO), Southwest Power Pool (SPP) as well as Ontario Independent Electricity System Operator (IESO). The second approach is being followed by PJM Interconnection (PJM), New York ISO (NYISO) and CAISO (for reliability projects). New England ISO (ISO-NE) proposes to use the first approach for public policy projects, and the second approach for reliability and market efficiency projects.


The projects that have been bid out through either competitive bidding or the hybrid process include the Competitive Renewable Energy Zone (CREZ) project, the East–West Tie transmission project, the Fort McMurray West transmission project, the Gates–Gregg transmission line project, and Artificial Island.


In the ERCOT region, the USD7 billion CREZ project was designed by the Texas Public Utility Commission (PUC) to enhance the transmission capacity of the region by 18 GW to accommodate renewable energy. The project was completed in 2013 with the addition of 5,782 km of transmission line length. The project was competitively bid out to 14 companies including non-incumbents. The selection was based on the capacity to finance, licence, construct, operate and maintain (O&M) facilities in a beneficial and cost‐effective manner, projected capital and O&M costs and schedule, among other things.


In Ontario, the Ontario Energy Board (OEB) bid out the East–West Tie transmission project through a competitive process in 2013. The project involves the construction of a new 400-km, 230 kV double-circuit line from the Wawa substation to the Lakehead substation in Thunder Bay, Ontario. The line has a transfer capacity of 650 MW. The project is essential to support the development of renewable energy in northwest Ontario and to maintain system reliability in the region. Six bids were received with significantly lower costs than the incumbent proposal. The selection was based on nine parameters, including organisation and project management, financial capacity, technical capability, schedule, design and construction, and cost, among other things. It may be noted that OEB evaluated costs based on the ranking of project development costs and completeness of the cost estimate and not necessarily on the lowest cost.


The project was secured by a consortium of NextEra Energy, Enbridge Incorporation and Borealis Infrastructure Management [a joint venture (JV) now known as NextBridge Infrastructure, formerly known as Upper Canada Transmission Incorporation or UCT]. The consortium was selected over five other qualified bidders (AltaLink, HydroOne, REC Canada & MEHC Transmission, Fortis, Iccon Netherlands and TransCanada). NextBridge is currently developing the project; the original timeline for completion of the project has been extended from the first half of 2018 to 2020.


In Alberta, the Fort McMurray West transmission project, which entails building a transmission line between Wabamun near Edmonton and Fort McMurray, is being developed by a JV of local utility ATCO Limited and Quanta Services. The JV was selected through the competitive bidding process in late 2014. The venture, called Alberta PowerLine, bid CAD1.43 billion for the project, which is intended to support development in the oil sands region of the province. The project was bid out competitively based on Alberta Electric System Operator’s (AESO) direction in 2010. This project was one of several designated by legislation in 2009 as ‘critical transmission infrastructure’. The project is based on a single owner model whereby the selected developer is responsible for all project activities including ownership, operation and maintenance of the facilities for 35 years. The consortium was selected over four other qualified bidders (Athabasca Transmission, NorSpan Partners LP, TAMA Transmission LP and TransCanada/Elecnor). All five companies invited to bid included local participation.


Alberta PowerLine, of which ATCO will own 80 per cent, submitted its application for the line to the Alberta Utilities Commission (AUC) in December 2015. Major components of the transmission line project include:



AUC’s approval is anticipated in November 2016, followed by construction beginning in January 2017. The new transmission infrastructure is expected to be in commercial operation by June 2019. The application also includes two route alternatives for the longer transmission line, but only one option for the shorter segment.


In California, CAISO awarded the Gates–Gregg transmission line project, a reliability project identified in the 2012-13 transmission plan, to the incumbent JV of Pacific Gas and Electric Company (PG&E), MidAmerican Transmission, and the non-profit Citizens Energy Corporation (Citizens Energy) in November 2013. The consortium was selected over four other qualified bidders (Elecnor, Isolux Infrastructure, Trans Bay Cable and Pattern Energy Group). The key selection parameters included experience in acquiring rights-of-way (ROW), current and expected capabilities to finance, licence, construct, and operate and maintain, as well as schedule and cost containment. Given that the non-incumbents did not have existing ROW, they were at a disadvantage as they would face additional costs, approvals and other difficulties.


As per the contract with the selected JV, the companies will develop, operate and own a 60-mile (96.6 km) transmission line to connect the Gregg substation, located north of Fresno, to the Gates substation, located southwest of Henrietta in Madera County. Both substations are owned by PG&E. The line will provide a link to the 500 kV transmission lines that connect northern and southern California. It will be built as a single-circuit line, but the towers will have the capacity for a second circuit to allow for future growth. The line is estimated to cost about USD115-145 million. The project is expected to be completed by 2020, with the construction works likely to commence in 2018-19.


In compliance with Order 1000, PJM followed the competitive transmission solicitation process for the first time for market efficiency projects (MEPs) in 2013. Subsequently, it invited proposals for the Artificial Island project, which aims to provide the transmission infrastructure required by the nuclear power plants (2,365 MW Salem and 1,178 MW Hope Creek projects) located on Artificial Island in southern New Jersey to maintain system stability.


In response to this, PJM received 26 proposals from seven proponents with cost estimates varying from USD116 million to USD1.5 billion and technology solutions including static VAR compensator (SVC) and high voltage direct current. After analysing the proposals, in 2014, Public Service Electric & Gas (PSE&G) was selected to construct the line. It proposed USD300 million worth of projects to resolve the issue. However, subsequently, the Board members of PJM reopened the bids and awarded the project to LS Power, which quoted USD146 million for the same. This decision was challenged by PSE&G, whereby it accused PJM of failing to follow its own rules by unilaterally modifying the finalists’ proposals and allowing LS Power to modify its proposal more than a year after the proposal window closed. In June 2015, FERC rejected PSE&G’s argument on the grounds that PJM had followed its commitment to evaluate Artificial Island proposals using its then-effective transmission planning process and to incorporate its new Order 1000 proposal window into that process ‘to the extent feasible and practicable’. According to FERC, PJM was not required to use its Order 1000 solicitation rules because the call for bids predated that measure.


Subsequently, in July 2015, PJM accepted the recommendations mentioned in its white paper on the project. Under this paper, PJM staff recommended splitting the power transmission network expansion work into three components:



In addition to the above, PJM has recommended the construction of a 300 MVAR SVC device at the 500 kV New Freedom substation. This is likely to be carried out by PSE&G. PJM staff has also recommended the installation of a high-speed optical ground wire (OPGW)-based communication system at several critical 500 kV circuits in the vicinity of Artificial Island. These OPGW upgrades will be carried out by PSE&G, PHI and FirstEnergy. PSE&G will also be responsible for tap settings for the step-up transformers at the three nuclear power plants (Salem 1, Salem 2 and Hope Creek) located on Artificial Island.


LS Power will be notified as the Designated Entity for the 230 kV transmission line portion of the solution. PJM will also draft the Designated Entity Agreement and Interconnection Coordination Agreements, which will detail the duties, accountabilities, obligations and responsibilities of each party.


In another development, in September 2015, FERC accepted the rate proposals of Kanstar Transmission, Midwest Power Transmission Arkansas and ATX Southwest, a wholly owned subsidiary of Ameren Transmission Company, to compete to build transmission infrastructure in unregulated markets. Under their filing, the companies separately submitted their transmission formula rate template and formula rate protocols to establish a mechanism to recover their costs associated with transmission projects that they intend to own and develop as part of the Order 1000 mandates of FERC. Kanstar Transmission and ATX Southwest operate in the service areas of SPP, and Midwest Power operates in the service area of MISO.


MISO is expected to issue its first competitive solicitation as part of the approved transmission expansion plan 2015 for the 345 kV Duff–Rockport–Coleman transmission line. Reportedly, it has close to 50 qualified developers including independent companies (with or without affiliations with utilities) as well as incumbent utilities.  The project, expected to be in service in 2021, should eliminate congestion around Newtonville and Coleman, and provide slightly higher economic benefits than the alternatives proposed.


In April 2015, SPP approved the 115 kV North Liberal–Walkemeyer project in Kansas in its first competitive portfolio and invited requests for proposal (RfP) subsequently in May 2015. The project involves the construction of a new 34-km (21-mile) line from the existing North Liberal substation to the Walkemeyer substation in Seward County; a new 345/115 kV substation to tap the existing 345 kV Hitchland–Finney line; and an approximately 2-km (1-mile), 115 kV line from the new substation to the Walkemeyer substation. Construction is scheduled to begin by 2018-19. SPP estimates the project cost at approximately USD35 million. It may be noted that there are close to two dozen qualified RfP participants or independent transmission developers who are members of SPP.


The provisions of FERC’s Order 1000 are certainly bringing a paradigm shift in the way new transmission infrastructure is being identified, planned, awarded and built. Independent transmission developers, which were earlier cautious to commit resources to new transmission projects due to the risks associated with the incumbent utility and ROFR, are now more willing to participate in the transmission development process, making the landscape more competitive. These developments are taking place at the opportune time when expansion of renewable resources and new gas generation (in compliance with the Clean Power Plan or CPP and other environmental regulations) are expected to demand huge new transmission infrastructure in the coming years.


New transmission developers have the advantage of being able to access capital from varied sources as well as the ability to work across utility territories. That said, the importance of local expertise and incumbent participation cannot be undermined as they continue to enjoy certain advantages such as local system knowledge and relationships with RTO planning groups; lower cost opportunities to upgrade existing facilities; as well as sharing of existing ROW. Therefore, tie-ups with local partners may often be useful for new players. The competitive bidding process followed by various regions/RTOs varies as it is still evolving. Net net, although evolving at a slow pace, foundations have been laid to ensure that more innovative and economic solutions are encouraged and available in regional transmission planning.