Operating Committee Meeting. Transmission Policy Training

Transcription

1 Operating Committee Meeting Fall 2010 New Orleans Transmission Policy Training Arnie Podgorsky Patrick Morand Wright & Talisman, P.C G Street N.W., Suite 600 Washington, DC podgorsky@wrightlaw.com morand@wrightlaw.com These materials are to assist in WSPP Training and do not state the views of WSPP Inc.

2 Transmission i Construction ti American Recovery and Reinvestment Act 1 The economic stimulus bill allocated $4.5 billion to the Department of Energy s Office of Electricity Delivery and Energy Reliability ( OE ). 2 In accordance with section 1306 of the Energy Independence and Security Act of 2007, 3 OE allocated approximately $3.5 billion of those funds to a matching grant program that covers up to 50% of investments planned for the deployment of Smart Grid technology. 4 1 American Recovery and Reinvestment Act of 2009, Pub. L. No , 123 Stat. 115 (2009) ( ARRA ). 2 See OE Frequently Asked Questions ( 3 Energy Independence and Security Act of 2007, Pub. L. No , 121 Stat (2007). 4 OE Program Specific Recovery Plan (June 11, 2010) at 5 (

3 Transmission i Construction ti (cont.) ARRA (cont.) There are six categories of Smart Grid investment: equipment manufacturing; customer systems; advanced metering infrastructure; electric distribution systems; electric transmission systems; and, integrated and/or cross-cutting systems. 5 Smart Grid investments in electric transmission systems are aimed at adding smart grid functions to the transmission systems in bulk power markets that typically involve power delivery over long distances including multi-state regions. 6 5 See 6 Id.

4 Transmission i Construction ti (cont.) ARRA (cont.) 7 Id. Smart Grid electric transmission projects will include, among others: adding smart grid functions to devices, equipment, and/or software applications; phasor measurement units; advanced communications and interconnection systems; and retrofit of electric transmission systems with smart grid functions and capabilities. 7 OE awarded over $147 million in Smart Grid electric transmission grants for projects within WECC, NYISO, Midwest ISO, PJM, ISO New England and elsewhere. 8 8 See

5 Transmission i Construction ti (cont.) Other construction According to a February 2010 EEI report, EEI members planned to invest $33.9 billion in their transmission systems between 2009 and The transmission investments included: transmission line and non-transmission line transmission system investments; transmission supporting the integration of renewable resources; and the transmission-related Smart Grid projects discussed d already. 9 Transmission Projects: At A Glance (February 2010) at vii, available at: _ Project _ lowres.pdf. 10 Id. at vi.

6 Regional Transmission i Planning ARRA Funded Transmission Planning From the $4.5 billion allocated to it, OE awarded a total of $60 million to promote collaborative long-term analysis and planning for the Eastern, Western and Texas electricity interconnections. 11 The awards were as follows: Eastern Interconnection Planning Collaborative ($16m) Eastern Interconnection States Planning Council ($14m) WECC ($14.5m) Western Governers Association ($12m) ERCOT ($2.5m) ERCOT with Texas government agencies ($1m) See 12 Id.

7 Regional Transmission Planning (cont.) Examples of Other Regional Transmission Planning Organizations California Transmission Planning Group Among its initiatives is planning coordination among CAISO, POUs and IOUs to take advantage of planning windows for the development of transmission plan for California. 13 Northeast Coordinated System Plan An effort by ISO New England, NYISO and PJM to ensure that the electric system is planned on a wider interregional basis and is proactive and well coordinated See 14 See

8 Transmission i Siting Transmission siting authority is usually left to the states. Per EPAct 2005, 15 the Secretary of Energy designated an area in the Mid-Atlantic region and one covering Southern California and part of western Arizona as National Interest Electric Transmission Corridors. The two National Corridors are populous regions with growing electricity congestion problems Energy Policy Act of 2005, Pub. L. No , 119 Stat. 594 (2005) ( EPAct 2005 ). 16 See

9 Transmission i Siting (cont.) Under EPAct 2005,and FPA 216, 17 FERC has the authority to issue a permit to construct transmission facilities within National Corridors if a state: withholds approval for more than 1 year; does not have the authority to site transmission i facilities; or cannot consider interstate benefits of the proposed project. FERC has not yet exercised this authority U.S.C. 824p.

10 Transmission i Incentive Rates Section 1241 of EPAct 2005 added section 219 to the FPA, 18 directing FERC to establish incentive based rate treatment for transmission investment. FERC issued Order No and its progeny to set forth the processes by which a public utility can seek incentive rate treatment for transmission infrastructure investment (e.g., section 205 filing or a declaratory order). An applicant must show the facilities (1) either ensure reliability or reduce the cost of delivered power by reducing transmission congestion, and (2) that there is a nexus between the incentive sought and the investment made U.S.C. 824s. 19 Promoting Transmission Investment Through Pricing Reform, Order No. 679, FERC Stats. & Regs., Regs. Preambles 31,222, order on reh g, Order No. 679-A, FERC Stats. & Regs., Regs. Preambles 31,236 (2006), order on reh g, Order No. 679-B, 119 FERC 61,062 (2007).

11 Transmission Incentive Rates (cont.) FERC will grant a rebuttable presumption that the project qualifies under section 219 if it results from a regional planning process or has been issued a CPCN from a state. The applicant still must demonstrate a nexus. Some of the incentives available pursuant to Order No. 679 include the following : ROE sufficient to attract capital CWIP and pre-commercial e c expenses Hypothetical capital structure Accelerated depreciation Deferred cost recovery Certain Transco-specific incentives including ROE incentive, Accumulated Deferred Income Taxes, acquisition premiums for Transco formation.

12 Transmission Incentive Rates (cont.) Examples of recent FERC decisions granting incentive rate treatment under Order No. 679: Great River Energy, 130 FERC 61,001 (2010). FERC granted Great River, for its 3 CapX2020 projects, 100&% CWIP, 100% abandoned plant recovery, and a hypothetical capital structure of 20% equity and 80% debt. S. Cal. Edison Co., 122 FERC 61,187 (2008), reh g denied, 131 FERC 61,020 (2010). FERC granted ROE of for the Rancho Vista project and for the Devers-Palo Verde II and Tehachapi h Transmission i projects.

13 Transmission Incentive Rates (cont.) Examples of recent FERC decisions (cont.): Pub. Serv. Elec. & Gas Co., 126 FERC 61,219 (2009), reh g denied, 131 FERC 61,028 (2010). FERC granted PSE&G, for its share of the Mid-Atlantic Power Pathway (MAPP) transmission expansion project, an ROE adder of 150 basis points, and 100% abandoned plant recovery. FERC granted the incentive rates contingent on the PSE&G portion of the MAPP project being approved as a PJM Regional Transmission Expansion Plan project. See also Green Energy Express LLC, 130 FERC 61, (2010) (FERC granted incentive rates contingent on the project being approved in the CAISO transmission planning process); Western Grid Dev., LLC, 130 FERC 61,056 (2010) (same).

14 Transmission i Planning NOPR Order No. 890 Review FERC required all transmission providers with OATTs to include certain transmission planning principles in Attachment K of the OATTs These planning principles included participation in regional transmission planning In regions without ISO/RTOs, transmission providers could comply with the regional planning requirement through organizations such as WestConnect, ColumbiaGrid, and Northern Tier Transmission Group

15 Transmission Planning NOPR (cont.) FERC s reasons for reform include: The lack of a regional transmission plan; Transmission needs driven by public policy; Obstacles to non-incumbent transmission project developers participation in regional transmission planning processes; The lack of coordination between transmission planning regions; and Cost allocations for new transmission may not be just and reasonable.

16 Transmission Planning NOPR (cont.) FERC s proposed reforms would require that: With respect to transmission planning: Local and regional transmission planning account for transmission needs driven by public policy; Improved coordination between neighboring transmission planning regions; and Elimination of any right of first refusal (ROFR) created by a jurisdictional tariff or agreement and that provides an incumbent utility with an undue advantage over non-incumbent transmission project developers.

17 Transmission Planning NOPR (cont.) FERC s proposed reforms would require that: With respect to transmission cost allocation, every public utility transmission provider: have in place a method for allocating costs of new transmission facilities included in the transmission plan resulting from its transmission planning process; Note: cost allocation methods may vary based on different needs (e.g., reliability, congestion relief, public policy, etc.) develop a method for allocating costs of a new interregional transmission facility between two neighboring transmission planning regions;

18 Transmission Planning NOPR (cont.) An example of a cost allocation problem: A methodology where, for facilities rated at 345 kv and above, 20% of the cost to repay the interconnection customer is allocated to all pricing zones within the RTO and 80% is allocated among pricing zones using a line outage distribution factor method The flow effects result in the allocation of upgrade costs being highest in the zone where the upgrades are constructed and diminishing with distance from that zone A pricing i zone with 12.7 MW of interconnection ti requests for every 1 MW of load in that particular pricing zone

19 Transmission Planning NOPR (cont.) An example of a cost allocation problem (cont.) This was the case for Otter Tail Power s pricing zone within the Midwest ISO. See Midwest Indep. Transmission Sys. Operator, Inc., 129 FERC 61,060 (2009). The Midwest ISO proposed, as an interim measure to address the problem, that the interconnection customer bear 100% of the costs of network upgrades rated below 345 kv and 90% of the costs of network upgrades rated at and above 345 kv. FERC accepted the proposal, explaining that it was a reasonable implementation of the flexibility allowed by Order No and that, [w]hile [it] did not receive unanimous support in the stakeholder process, it did receive approval by the stakeholder vote and the Midwest ISO Advisory Committee vote.

20 Transmission i Loop Flow Loop Flow Defined: it is the difference between scheduled and actual flow on a path or interface NYISO Case: In 2008, FERC enforcement staff investigated allegations by NYISO that several of its market participants engaged in market manipulation by exploiting a seam in the pricing methods used by NYISO, PJM, Midwest ISO and Ontario s Independent Electricity System Operator (IESO). NYISO alleged that the market participants had disguised the true source and sink of the scheduled transactions at issue, resulting in physical flows substantially at variance from the scheduled flows.

21 Transmission i Loop Flow (cont.) NYISO Case (cont.): Specifically, the market participants scheduled over two paths : Path 1 (NYISO-IESO-MISO-PJM) and Path 5 (PJM- NYISO-IESO-MISO). NYISO alleged that these circuitous schedules resulted in uplift costs. For example, with Path 1, the scheduled flow was NYISO- IESO-MISO-PJM (over NYISO s less expensive western border), while the actual flow was NYISO-PJM (over NYISO s more congested and more expensive seam) FERC found no manipulation because the market participants simply responded to price signals, seeking to make a profit, and not artificially affect price.

22 Transmission i Policy Training i The End