Cross-Border Bargaining

Deck: 

Interregional grid planning under FERC Order 1000.

Fortnightly Magazine - October 2013

Now that the Federal Energy Regulatory Commission has ruled on the various protocols proposed by the nation’s major grid groups to comply with the commission’s highly controversial, landmark Order 1000 on regional transmission planning, let’s examine the other half of FERC’s vision: the mandate that each region also must coordinate with each of its neighbors to explore ideas for interregional grid projects – projects that might prove superior to those already approved at the regional level.

As we’ll see, interregional planning is proving no less contentious than the regional variety.

Order 1000 required all public utility transmission providers to band together in geographic areas to participate in regional planning to identify and study new grid projects to meet needs posed not just by reliability standards, but also by economics and public policy mandates such as renewable portfolio standards. It also required planners to select certain projects to have their costs allocated across the planning region according to a method to be defined as part of the regional plan, and to make sure that any transmission projects so selected can be built and owned by “non-incumbents” – i.e., developers other than the incumbent load-serving distribution utilities who historically have built and maintained the nation’s electric grid networks.

Now we turn to the interregional mandate. Here, the FERC order requires those same transmission providers who have formed the various grid planning regions to go further and coordinate and share data – one region with another – such that each pair of neighboring regions might work together, as instructed by FERC, to “identify and jointly evaluate interregional transmission facilities that may more efficiently or cost-effectively address the individual needs already identified in the first instance through their respective local and regional planning processes.”

As FERC required for regional plans under Order 1000, the interregional phase calls for regions to define a cost allocation method. This new interregional method will apportion between the two regional neighbors all the costs of any cross-border grid project approved through interregional coordination.

FERC’s mandate, however, will require more than just one cost allocation method per region. In fact, it will require multiple permutations: a separate consensus and agreement between each and every respective pair of adjoining regions. That means, for example, that the Southeast Region, including Southern Company, Duke, and TVA, must devise and put in place no less than five potentially different interregional cost allocation methods: one for each of its five regional neighbors, those being PJM, MISO, Florida, South Carolina, and the Southwest Power Pool.

To keep things simple, let’s focus on just three case examples of proposed agreements between three pairs of neighboring regions: PJM-MISO, MISO-SPP, and Southeast-SPP.

Thinly Veiled

In theory, interregional planning between PJM and the Midcontinent ISO (MISO), both certified by FERC as regional transmission organizations, ought to be fairly easy. After all, the two RTOs won FERC approval nearly a decade ago, back in 2004, for their bilateral Joint Operating Agreement, a deal that put in place just about all of the elements that FERC is requiring in Order 1000 for interregional compliance.

The PJM-MISO JOA specifies both (a) a bilateral process for the two RTOs to coordinate planning on cross-border projects, including tie-lines that span the seam dividing the two regions, and other projects located wholly within one RTO but built to serve a need arising in the other, and (b) a cost allocation method for projects approved under the JOA.

Figure 1 - Southeast and Neighboring Regions

And in fact, PJM has proposed to FERC that the commission should accept the JOA provisions (with certain tweaks and amendments) as providing enough guidance and specificity on interregional coordination and cost allocation for PJM to comply with Order 1000. (See, FERC Dkt. ER13-1944, filed July 10, 2013).

Nevertheless, the two regions now find themselves at odds. Their disagreement stems largely from MISO’s recent internal decision, noted in a prior column (see, “First Refusers,” February 2013), to give up on any region-wide allocation of costs for grid projects that MISO calls baseline reliability projects, and instead to assign all BRP project costs to the MISO pricing zone where the BRP would be located. 

This move by MISO, which FERC approved last spring at the same time that it ruled on MISO’s Order 1000 regional compliance (142 FERC ¶61,215, Mar. 22, 2013), was seen at the time by some as a ploy to preserve exclusive rights for its member transmission owners to build any and all grid projects dealing with reliability. The reason stems from FERC’s rule in Order 1000 barring any such preemptive “rights of first refusal.” It does so only for transmission projects selected in the regional plan for regional allocation – ROFRs would still be allowed for grid projects whose costs are allocated locally, as is now the case for MISO BRPs.

But there’s more. MISO also is telling FERC that the JOA won’t work for Order 1000 interregional compliance, as PJM claims.

MISO insists (and FERC rules would seem to confirm this) that its internal policy switch on cost allocation for reliability projects – abandoning any region-wide allocation for BRPs – makes it impossible for it to use the JOA with PJM to comply with the interregional half of FERC Order 1000, at least for cross-border BRPs.

FERC’s Order 1000 states that for a cross-border, interregional grid project to be eligible for interregional cost allocation, it first must have been selected for regional cost allocation in the regional plans of each of the two regions that put forward an interregional coordination – a requirement that MISO BRPs no longer meet.

Instead, MISO offers two new proposals for reliability projects: one for tie-line projects that physically connect one RTO with the other, and a second for projects built wholly within one RTO to serve a need arising in the other. Tie-line costs would be allocated based on RTO boundaries. Cost allocation for non-tie-line projects would be settled through negotiations between the constructing transmission owner and the non-constructing TO (the one that actually needs the project built), with the constructing TO entitled to cancel the project if the parties can’t agree. (FERC Dkt. ER13-1943, filed July 10, 2013.)

MISO’s alternative proposal has sparked all manner of protest, not only from MISO’s interregional partner PJM, but from utilities and regulators as well.

After all, the JOA specifies a much more precise regime of interregional cost allocation.

For economic projects, known as cross-border market-efficiency projects (CBMEPs), the JOA allocates costs between the two RTOs based their respective shares of project benefits (a 70/30 weighting of energy production cost savings and reductions in net payments assigned to load). MISO appears to support this cost allocation method for economic projects for interregional compliance.

But for baseline reliability projects (CBBRP) – where the JOA requires a violations-based DFAX (distribution factor) method, which reflects each region’s respective share of power flows on the constrained facility or facilities necessitating the upgrade – MISO believes it must seek another way.

And so MISO is suggesting – for reliability projects at least – that grid owners will negotiate on the fly. And if talks break down, the project just gets canceled.

PJM’s transmission owners decry such an idea, which they see as a bid by MISO to re-write the JOA unilaterally. The PJM RTO terms the MISO proposal “a step backwards.”

PJM notes that while FERC Order 1000 would grant final authority to RTOs on interregional planning and expansion, “MISO proposes to transfer the decision-making responsibilities … to the individual transmission owners across the RTO regions,” giving them “unfettered discretion to decide whether or not a single RTO project needed for reliability by another TO in a neighboring region will be constructed.” (Protest of PJM, p. 19, FERC Dkt. ER13-1945, filed Sept. 9, 2013.)

The Ohio Public Utilities Commission goes further, calling MISO’s proposal “a thinly veiled attempt to protect the ROFR of its transmission owners, to the detriment of PJM, PJM TOs, and borders states along the PJM-MISO seam.” (Comments, Ohio PUC, p. 5, FERC Dkt. ER13-1945, filed Sept. 9, 2013.)

The irony, however, is that the JOA has performed woefully as a mechanism for getting cross-border projects built.

Testifying recently in support of MISO’s proposal for interregional coordination with PJM, filed this past summer at FERC to comply with Order 1000, Jennifer Curran, MISO’s v.p. of transmission, let the truth out:

“To date,” said Curran, “no cross-border projects have been approved for cost allocation under the existing JOA provisions.”

Northern Indiana Public Service Co. concurs, noting that “a joint coordination plan where nothing gets built is not a joint coordination plan, but instead a joint discussion.”

For its part, MISO argues in its interregional compliance proposal (see p.34) as if the JOA was never going to be of much help anyway, such that MISO’s apparent step back from the JOA provisions for reliability projects shouldn’t be of much concern:

“This change,” writes MISO, “does not have any immediate or foreseeable impact on implementation of the MISO-PJM JOA.

“As explained by Ms. Curran, there has never been an identified CBBRP in the history of the JOA, nor is one currently under consideration.”

Skewing the Results

Negotiations between MISO and the Southwest Power Pool on protocols for interregional coordination and cost allocation have sparked many of the same arguments we saw with the MISO-PJM proposals. That’s because MISO’s elimination of any region-wide cost pass-along for reliability grid projects approved through its own internal regional planning process will create the same problems in crafting an agreement with SPP, as with its dealings with PJM.

But the really interesting wrinkle in the SPP-MISO discussions surrounds Entergy’s merger with ITC and its coming integration into MISO. The Entergy deal has soured both SPP and its member transmission owners, who have long fretted that power transfers between Entergy and MISO will impose invasive and unwanted loop flows across the SPP grid, without adequate compensation, forcing SPP TOs to subsidize the Entergy deal.

(Readers seeking to learn more about this loop flow issue should take a look at FERC Docket ER13-1864, in which the Southwest Power Pool has proposed certain revisions to its JOA with MISO regarding terms and conditions for “market-to-market” procedures, and where SPP transmission owners have questioned whether compensation for loop flows created by the Entergy integration should be dealt with under FERC’s “traditional” policy, which envisions a voluntary settlement between affected parties, or whether such loop flows should be treated as intentional flows, for which compensation should be paid pursuant to rates in filed tariffs.)

Now, however, with SPP and MISO filing interregional compliance plans under Order 1000, we see the loop flow issue morphing into an entirely new dimension.

Available space here doesn’t permit analysis of all the ramifications, but it appears that SPP’s transmission owners now fear that MISO might be seeking to gain greater control over design, construction, and ownership over the portion of any new interregional, cross-border grid lines located with SPP territory. And as the SPP TOs argue, MISO could achieve that simply by re-working the definition of project benefits included in the interregional cost allocation formula that will bind the two regions.

Consider the following: For interregional coordination with SPP under Order 1000, MISO proposes an interregional cost allocation method only for MEPs – economic projects. And while it proposes to allocate costs for any such cross-border MEPs based on the respective ratios of benefits accruing to each region, it wants to employ a benefit metric that reflects only the change in adjusted energy production costs (APC). It wouldn’t recognize benefits stemming from a change in net payments for energy by load. (See, FERC Dkt. ER13-1938, filed July 10, 2013.)

Thus, according to the SPP grid owners, this intended emphasis on production costs has a sneaky purpose. As the TOs explain, it has been widely predicted that the integration of Entergy into MISO will achieve production cost savings for the rest of MISO. And the more grid lines built across SPP territory that interconnect with MISO and boost its capacity to trade with Entergy, the greater those production cost savings presumably will be.

Now take a look at one of MISO’s proposals in its interregional compliance filing with SPP. According to one of MISO’s proposed revisions for its JOA with SPP – Section 9.7.1: “Interregional Project Construction and Ownership” – the entity entitled to “construct, implement, own, operate, maintain, repair, restore, and finance” a MISO-SPP interregional tie-line will be determined based on the proportion of benefits calculated for the project. (See, “MISO Transmittal Letter,” p. 17, FERC Dkt. ER13-1938, filed July 10, 2013.)

Thus, given the claimed northward predominant flow of production cost benefits from the Entergy integration, plus MISO’s proposal to limit recognition of cross-border project benefits to production costs only, the SPP grid owners fear what they call a “skewing” of results.

Here’s their argument:

“MISO’s asymmetrical eligibility proposal would give MISO the opportunity to build and control any type of facility on the SPP system… By limiting the type of benefit … MISO’s proposal may be skewing the results… [A]s has been documented elsewhere, integration of Entergy into MISO is predicted to achieve production cost savings for MISO. If new facilities across SPP would further those savings, MISO’s one-dimensional test, which would disregard the local reliability benefits of such a line, could give MISO an advantage in efforts to control a large portion of the new line…

“The SPP TOs recognize that transmission systems often overlap, and we are not making these observations out of some misplaced sense of territorial protectionism – just the opposite, in fact …

The criteria for determining eligibility for interregional status should be the same on both sides of the border, and the tests for benefits should include all recognized forms of benefits, not just those that may favor the growth of one RTO over the other.” (See, Comments of SPP TOs, pp. 5-6. FERC Dkts. ER13-1937, 1938, filed Sept. 9, 2013.)

As of September 25, neither MISO nor its transmission owners had appeared to respond to these charges on the record in either of the two FERC cases involving MISO-SPP interregional coordination under FERC Order 1000.

But the SPP RTO has filed its own objections to certain MISO proposals.

First, as did PJM, SPP opposes MISO’s plan to exclude reliability projects from any interregional coordination, planning, and cost allocation. With interregional coordination reserved only for economic projects, SPP complains that opportunities for cross-border collaboration will be restricted unreasonably.

One reason lies with MISO’s minimum voltage threshold of 345 kV that applies to MISO-approved cross-border MEPs (no more than 50 percent of project costs can be attributable to lower-voltage facilities). But according to SPP, 80 percent of its interconnections with MISO are at a voltage level less than 345 kV. (See Exh. SPP-4, Testimony of David Kelley, p.11, FERC Dkt. ER13-1937, filed July 10, 2013.)

Thus, as SPP explains, removing lower-voltage projects from consideration “may encourage a less cost-effective solution, as high-voltage projects are typically more expensive.” (See, SPP Comments, p.23, FERC Dkt. ER13-1938, filed Sept. 9, 2013.)

But SPP goes further. If interregional cost allocation is to be limited to economic MEP projects, as MISO proposes, the Arkansas-based RTO wants to add a benefit metric for allocating costs that will reflect and capture the avoided costs of any reliability projects that the economic project might possibly delay or displace.

In fact, SPP proposes at some later date to develop and propose still another benefit metric for cross-border economic projects that would capture any occasional benefits related to satisfying public policy requirements.

“Adjusted Production Cost,” as SPP notes, “is not an appropriate metric to quantify reliability or public policy benefits …

“Additionally transmission solutions needed to meet public policy requirements are not always economical.”

Worth the Cost?

The largest of the Order 1000 planning regions, the Southeastern Regional Transmission Planning Process (or SERTP for short), which includes Southern Company, Duke, and TVA, proposes a cost allocation method for cross-border projects – the avoided cost method – that FERC already has rejected at the regional level, both for South Carolina (Dkt. ER13-107, Apr. 18, 2013, 143 FERC ¶61,058), and in fact for the Southeast as well (Dkt. ER13-908, July 18, 2013, 144 FERC ¶61,054).

Yet the Southeast now has won agreement for this method at the interregional level from four of its five neighboring regions: PJM, MISO, Florida, and South Carolina. The Southwest Power Pool remains the only holdout.

The Southeast defends its avoided cost method as permissible for interregional cost allocation since in its view, the reasons given by FERC for killing it in regional plans (i.e., that avoided costs fail to capture economic or policy benefits) shouldn’t apply at the interregional level. That’s because FERC Order 1000 didn’t establish interregional coordination as a separate free-standing planning process, empowered to study economic and policy needs, but only as a sort of second set of eyes, to review the regional plan one more time.

In its proposal for compliance under the interregional phase of Order 1000, the Southeast explains why an avoided cost method should suffice:

“Utilizing an avoided [or] displaced cost allocation metric facilitates the comparison of the costs of an interregional project with a project(s) which has already been determined to provide benefits to the planning region.” (SERTP Interregional Compliance Filing, p. 12, FERC Dkts. ER13-1928, 1930, 1940 & 1941, filed July 10, 2013.)

In other words, in SERTP’s view, the regional plan assesses the value and merit of project benefits from meeting reliability, economic, or policy needs. After that, you simply look to see if you can capture those exact same benefits at the interregional level with a cheaper project.

MISO and PJM have acceded to an avoided-cost method at the interregional level. However, they have each proposed – and SERTP appears to have agreed – that they will continue to explore other cost allocation methods for interregional planning, to ask for FERC approval if such other method is deemed suitable by the Southeast.

And for the record, the SERTP at this writing hadn’t yet returned to FERC to file a new Order 1000 regional plan to substitute for the one (with the avoided cost method) that the commission rejected on July 18. So we don’t yet know how the Southeast eventually will design its new preferred benefit metrics and cost allocation method for Order 1000 compliance at the regional level. In fact, on September 20, SERTP asked the commission for an extension of time, to Jan. 14, 2014, to file its amended regional plan.

As hinted above, the Southwest Power Pool doesn’t share SERTP’s enthusiasm for the avoided cost allocation method. Instead, SPP wants stakeholders at the interregional level to be able to propose projects that will address needs not already considered or included in the regional plan. The Southeast takes umbrage, accusing SPP of wanting to introduce top-down grid planning at the interregional level, usurping its preference for bottom-up transmission planning centered on state-regulated integrated resource planning.

As it did when it filed its regional plan, the Southeast insists that a transmission plan should not drive grid construction: rather, that state-approved IRP findings should serve as data inputs that govern the trajectory of grid expansion.

And as part of its interregional compliance filing, SERTP re-submitted an affidavit taken several years ago from Bryan K. Hill, at that time a transmission planning manager for Southern Company, declaring that “any perceived lack of interregional facilities in the Southeast does not indicate a failure of the planning processes to analyze such facilities, but instead a failure of those facilities to be worth the cost.”