An expiring 40-year-old contract rocks the Pacific AC Intertie.
Bruce W. Radford is editor-in-chief for Public Utilities Fortnightly.
In August 1967, with the “Summer of Love” in full swing, the utility we now know as PacifiCorp agreed to lease all its capacity on a major North-South transmission line to the San Francisco utility, Pacific Gas & Electric Co. (PG&E), for the fixed annual rent of $475,000.
Today, after 40 years, with that rate now way below market, PacifiCorp believes it is high time to share the love.
Three months ago, PacifiCorp filed a notice at the Federal Energy Regulatory Commission (FERC) to inform FERC, PG&E, and the state of California that it would not renew the contract upon its long-anticipated expiration date of July 31, 2007. Instead, it would take back full ownership of its transmission-line rights and sell the available capacity into the open market under its own tariff at today’s going rate. (See, FERC Docket No. ER07-882, filed May 9, 2007.)
But there’s a problem. It’s called rate shock. According to Lanette Kozlowski, manager of tariffs and regulation in PG&E’s department of electric transmission rates, who has studied PacifiCorp’s Open Access Transmission Tariff (OATT) currently on file at FERC, this new rate could run as high as $68 million per year. That makes for a 14,300 percent increase, according to her calculations, as against the 1967 contract rate that PG&E has been paying. And this increase would come in the form of an additional pancaked transmission charge. Market participants exporting power from the Pacific Northwest and California could no longer pay just one grid-access charge from Malin, Ore., to reach Southern California.
And that’s not all. Because of escape clauses contained in other related contracts and legal settlements ironed out over years (most recently in a key 2004 FERC decision), PacifiCorp’s notice throws the entire regional transmission grid into chaos. Like a train of falling dominoes, PacifiCorp’s decision not to renew the 40-year-old, below-market contract will “undo” a broad package of longstanding and interlocking agreements on grid operating protocols for Northern California and the Pacific Northwest.
Heretofore, the California Independent System Operator (Cal-ISO) has managed operations on the PacifiCorp line, a 47-mile, 500-kV segment that runs south from Oregon into California, where it joins a matching 47-mile segment owned by PG&E. This 94-mile line (“P”), plus a second and parallel 94-mile, 500-kV line (“W”) owned by the Western Area Power Administration (WAPA), together form the Pacific AC Intertie (PACI—known as PACI-P and PACI-W), running between the Malin (Oregon) and Round Mountain (California) substations.
In fact, the Cal-ISO serves as path operator for the entire California- Oregon Intertie (COI), also known as “Path 66,” which provides 4,800 MW of rated transfer capacity in a north- to-south direction (somewhat less from south to north.)
The COI includes not only the entire PACI, but also the California-Oregon Transmission Project (COTP)—a third and much longer 500-kV line completed in the early 1990s. Moreover, in its role as path operator, the Cal-ISO works closely with the Bonneville Power Administration (BPA), which controls and operates the same path as it extends north into Oregon and beyond. But the Cal-ISO’s authority has depended in no small part of the 1967 contract, which put PACI capacity in the hands of PG&E, which then turned it over to ISO control as part of California’s industry restructuring. (See Figure 1, “Pacific Intertie and COTP Facilities.”)
Thus, at the very least, PacifiCorp’s decision not to renew the out-of-date contract would undo a series of longstanding agreements regarding line operations and sharing of curtailment costs along the entire COI—the highway that facilitates power imports and exports between California with the Pacific Northwest.
At the worst, the PacifiCorp announcement, if not followed up by successful settlement discussions and new agreements, could even force a redrawing of geographic boundaries between the BPA and the Cal-ISO, which run the two largest balancing and control areas in the West.
And for the Cal-ISO, that’s not what you would want to see at the end of July, at the height of the summer peaking season, and just six months from Feb. 1, 2008—the planned start date for its new MRTU rate overhaul, the Market Redesign and Technology Upgrade.
In a Pickle
No obvious villain emerges in this case. PacifiCorp simply wants to update a rate that for years has fallen below market. Its opponents, meanwhile, seek to ensure continued reliable operations of a key regional grid interface.
By all accounts, PacifiCorp began early on—a good six months prior to the July 31 contract termination date—to open up negotiations with all affected parties. Rich Bayless, PacifiCorp’s transmission strategy director, began searching for a solution in an e-mail message he sent in January to Jim Detmers, vice president for operations at the Cal-ISO:
“As we discussed on the phone,” wrote Bayless, “we’re in somewhat of a pickle with the Malin-Indian Springs contract expiring this year.
“I think we’ve tumbled to the fact that no matter which way we head on the expiring contract, we will have parties on one side or the other challenging our action at FERC. …
“Timing is a problem … since the contract expires in August.
“Representatives from our Transmission Services and Operating groups would like to come down and discuss options with the Cal-ISO.” (See, Appendices 2-8, e-mail exchanges and correspondence, Jan. 8 to May 24, 2007, PacifiCorp’s Answer to Comments, FERC Docket No. ER07-882, filed June 18, 2007.)
The record shows that informal discussions and negotiations continued for some time, with the ISO outlining various options. For instance, one option would have PacifiCorp joining the ISO’s controlled grid as a participating transmission owner (PTO), so that it might step into the shoes of PG&E. (Without joining the ISO, any service that PacifiCorp might offer after contract expiration would come under its own tariff. The Cal-ISO tariff regime for grid access and congestion would not apply, nor would the ISO provide scheduling or balancing services in its role as control area operator.)
The give and take concluded in a letter exchange between Detmers and Kenneth Houston, director of transmission for PacifiCorp, in which the ISO laid out its concerns with operations and reliability, and PacifiCorp answered in terms of market imperatives.
Writing on March 29, ISO Vice President Detmers identified three key concerns.
First, removal of the line from the ISO’s “controlled grid,” without shifting the control area boundary, would complicate reliable operation of the larger COI path.
Second, the new pancaked wheeling charge (paid under PacifiCorp’s tariff) would make PACI more costly to use and push traffic onto the WAPA line (PACI-W). This uneven pricing could generate congestion charges and result in what the ISO called “a minimum standing usage charge” (a congestion charge) on PACI-W.
Third, switching service and tariff responsibility to PacifiCorp on its 47-mile line segment would force the ISO to redesign its network model. That means the topology that maps buses, nodes, and switches, and interfaces on the grid. The ISO might need to create a new locational pricing node at the Indian Springs demarcation point between PacifiCorp and PG&E line segments (the latter falling under ISO control).
This step would prove difficult because Indian Springs is not a substation, bus, or node, but actually is nothing more than a transmission tower, like any other. When PacifiCorp and PG&E combined efforts to build the 94-mile PACI-P line during the 1960s, that is the point they chose to delineate ownership of their respective projects. Now, however, to accommodate scheduling at that point, with the calculation of locational marginal prices and allocation of congestion revenue rights, it seems that the ISO either would need to create what it calls a “P-Node” at the Indian Springs tower, or else redraw its boundary lines with Bonneville Power, so that the Cal-ISO would end at Indian Springs, Calif., instead of Malin, Ore. Either way, this additional software programming would cause problems, especially with the MRTU startup date looming nearer. Detmers explains:
“In 2007, the California ISO currently plans to make necessary changes to the network model in two scheduled ‘builds,’ one in May and one in September. Each ‘build’ typically requires a 2- to 3-month process. Planning for the May build has already concluded.
“Network model changes require full system and software testing and a market simulation. … Our ability to make the network model and system changes necessary to accommodate PacifiCorp’s request prior to expiration of the contract is challenged.”
Kenneth Houston then answered each charge in turn, emphasizing that PacifiCorp would gladly participate in a re-negotiation and signing of the various operating agreements then in force to govern control and operation of the COI. That would include a restated OCOA, the Owners Coordinated Operating Agreement, which had been approved by settlement at FERC in 2004.
Note, however, that Houston offered an intriguing argument to counter the ISO’s concerns over rate pancaking, congestion, and line loading on PACI-W.
Houston claimed that while PacifiCorp’s proposal indeed would create an additional pancaked charge, market participants might prefer that to unknown risks of the Cal-ISO’s looming market redesign. Thus, PacifiCorp’s pullout might not distort flows as much as the ISO feared:
“As you know,” wrote Houston to Detmers on April 12, “market participants that choose to schedule on the Cal-ISO PACI-W line will not only pay wheeling fees, but will also pay other Cal-ISO charges, such as congestion fees and grid management charges. …
“PacifiCorp believes that market participants will make the most economical choice after considering all charges related to their transactional options.”
Once the contract termination notice was filed, the discussion deteriorated a bit. Faced with overwhelming opposition, PacifiCorp claimed that its good-faith attempts to negotiate ahead of time had been “effectively stonewalled, and then pilloried.”
It suggested that opponents wanted to block the contract termination so that they might “unjustifiably continue to enjoy the benefits of the low-cost-deal they now have.”
Carve-outs and Encumbrances
At its core, this dispute reveals something of a dirty little secret percolating across the Western Grid.
On one hand, it seems that the California utilities, both public and private, are content to allow a large regional grid management agency (such as the Cal-ISO or the BPA) to exercise regional control in scheduling, balancing, and allocating capacity rights on the region’s major transmission lines. In that way, congestion and curtailments are spread evenly among all competitors in a physical sense.
However, when it comes down to the crunch, those same utilities—and public power in particular—would prefer to set their own rates. They each want to offer transmission service under their own tariffs—the OATT that each utility must file now under FERC Order 890, which brings even public power under a modicum of FERC regulatory control.
By providing service under their own individual tariffs, each utility wins immunity from liability under the typical ISO financial regimes that assess special charges to allocate congestion and hedging rights, such as locational marginal pricing, financial transmission rights (FTRs), and, in California, congestion revenue rights.
Nevertheless, it is from these financial settlements that come the revenues that fund the operations of the ISOs and the regional transmission organizations. It is the grid access and management charges—and the other related charges that public power so much wants to avoid—that make possible the physical regional control that is so much desired.
In short, the public-power utilities want to have their cake and eat it to.
In this case, even though the various agreements provide for the Cal-ISO to serve as “path operator” for the COI, to ensure integrated operations and a sharing of curtailments in a way that serves broad regional interests—including BPA hydropower resources and a large number of public power entities that enjoy physical rights contracts—not all is as it seems.
In reality, the COTP has been permitted to join a different balancing area (the SMUD area, controlled by the Sacramento Municipal Utility District) from the two PACI lines, even though one of the three lines falls under the common control of Cal-ISO as path operator. That is one of the rights assured by the OCOA, as part of the 2004 FERC settlement ruling.
Second, the federal power marketing agency, WAPA, also has arranged for its proprietary PACI-W line to fall under the umbrella of the Cal-ISO’s path operator function. It won this assurance under the same 2004 OCOA settlement ruling at FERC. Moreover, that 2004 FERC decision also granted WAPA a “carve-out” from the Cal-ISO grid, allowing it to provide transmission service to itself over the PACI under its own tariff, without risk or liability of having to pay the Cal-ISO grid-access charge or congestion charges. In this way, the WAPA substation at Tracy operates as a “subcontrol area” of the SMUD balancing area. WAPA is given an “encumbrance” that allows it to gain access across the ISO grid in Northern California to the Central Valley Project, but without having to accept the risks and liabilities of status as an ISO market participant. It’s a lot like the explanation you will hear from the Pennsylvania Amish: WAPA is “in” the ISO grid, but not “of it.”
These unusual rights were quite controversial at the time. Southern California Edison had argued vehemently in 2004 that such encumbrances violated Cal-ISO tariffs. Edison had asserted that the Cal-ISO lacked authority to provide transmission services to certain privileged customers on terms different from those stated in its tariff applicable to ordinary market participants.
Nevertheless, FERC had allowed these special carve-outs because they were crafted as part of an overall indivisible settlement agreement. (See Docket No. ER04-688, Order issued Dec. 3, 2004, 109 FERC ¶61,255.)
Thus, PacifiCorp here is asking for nothing more than what various other public-power entities already have received. It wants the stability of overarching ISO control over the region’s largest N-S grid interface, but with the opportunity and economy to self-serve its own transmission needs and those of its customers, under its own tariff.
Of course, from the ISO side of things, the simplest solution to breaking the deadlock would have PacifiCorp joining the Cal-ISO as a full-fledged participating transmission owner. But you can imagine how that would play in Oregon.
“PacifiCorp understands,” as PacifiCorp grid manager Ken Houston wrote to Detmers in April, that “Cal-ISO would prefer that PacifiCorp become a participating transmission owner.”
But Houston also was tied to reality.
“The PTO approach is the most beneficial solution for the Cal-ISO and the customers of the Cal-ISO,” he acknowledged.
“However, it is not the most beneficial solution for PacifiCorp’s wholesale and retail customers.”