US Power Generating (USPG) entered into a definitive agreement and plan of merger with Tenaska Capital Management (TCM). Pursuant to the terms of the agreement, USPG will become a wholly-owned indirect subsidiary of TCM. Under the terms of the merger, TCM will purchase USPG, with the final price being determined by a number of business and tax adjustments. Consummation of the merger is subject to customary conditions including approvals of the Federal Energy Regulatory Commission and the New York Public Service Commission.

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 interregionalgrid 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.

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.”

For proponents of a clean energy economy, identifying the “good guys” is no easy task. 

Teaching a course in energy law and regulation at Vermont Law School a few summers ago, this author posed several questions to students about their views on clean energy. The students, almost to a one, had chosen the school for its environmental law program and their personal interest in a green future. And they brought to the classroom their own conceptions about who the good guys are in the energy economy. They came away, one hopes, with the understanding that identifying the good guys can prove immensely complicated – even where the policy goal (to promote clean energy) seems unambiguous.

The students grappled with a number of questions. What did they think about the importance of energy from wind? From solar? What of conservation? Of energy efficiency? Energy storage technology? Aren’t efficiency, conservation and storage all as green as renewable energy? These were all good things to be promoted, they said. But do they compete with one another and, if so, are some worth subsidizing over others? Are any worth subsidizing? Their answers to these questions were more equivocal. And the class, conducted several years ago, didn’t even touch on the more recent fracking debate or the explosive growth in oil production in North Dakota or from tar sands in Canada. But if the class were taught today, the list of questions would logically grow. Is hydraulic fracturing safe? Will it reduce carbon emissions? Should we be promoting its use to replace coal in power plants or oil in motor vehicles? Will it retard or hasten the arrival of a clean energy economy? How will the availability of cheap natural gas for transportation affect the development of electric or hybrid vehicles? How important is North American energy independence? If oil is going to be consumed anyway, is it better to rely on domestic sources? Can they help make us greener in the long run or will they slow progress?

Regulators, law makers, environmentalists, consumer advocates and energy industry participants will be asked these and similar questions if they aren’t already posing the questions themselves. And if they are conscientious, they will struggle for answers.

What is Green Anyway?

The broad and even overwhelming scientific consensus states that manmade carbon emissions are accelerating global warming.¹ But it isn’t just the climate change skeptics who have questioned the merits of the various strategies proposed to reduce the size of our global carbon footprint. As a society, we might well agree on the need to meet defined levels of CO₂ reductions or the related goal of domestic energy independence,² yet disagree – and vigorously – on how to get there.

Many states, for example, have chosen to adopt renewable portfolio standards (RPS). These rules can mandate a generation mix for utilities that must include certain percentages of identified renewable resources by a date certain.³ This strategy will have the effect of reducing carbon use to the extent renewable generation displaces generation that consumes more carbon.

Suppose, however, that some resources are considered more renewable than others. In California, local utilities must attain certain targets for renewable energy portfolios, but renewable generation located outside the state counts less – or not at all – toward those targets⁴ Similarly, the state has developed a “low carbon fuel standard” that applies to “any transportation fuel … sold, supplied or offered for sale in California,” but that measures carbon intensity by including the amount of carbon used to produce and transport the fuel to California.⁵ So, for example, a gallon of ethanol produced in Brazil would have a higher carbon intensity than an otherwise identical gallon produced in California. In both the RPS and carbon standard cases, the apparent goal isn’t simply to reduce carbon emissions, but to promote in-state development of renewable resources and the boost it might give to the local economy. 

In certain other states, large-scale hydroelectric projects – both existing and new – don’t qualify at all as “renewable.” Yet hydroelectric power serves as the quintessential example of a physically renewable resource: it rains, the rain evaporates, the water vapor condenses, and the cycle starts all over again. Policymakers in some states, though, have decided that counting existing hydroelectric projects toward renewable energy targets would give an insufficient incentive to utilities to expand their use of renewable resources – particularly in areas with plentiful hydropower resources. The argument for disqualifying new large-scale hydro is more difficult. Smaller-scale renewable energy resources, even small-scale hydro, often can’t compete with far lower cost large-scale hydroelectric plants. And most of the potential for large-scale hydroelectric projects isn’t in the United States, but in Canada.⁶ So disqualifying these projects serves not simply to reduce carbon emissions, but to protect nascent, homegrown renewable energy producers. Who are the good guys in that debate?

Here’s a more fundamental question. Are renewable energy portfolio standards – even those that are neutral as between various types of renewable resources – the best way to reduce carbon emissions? Economists generally agree that the best way to reduce carbon emissions is to tax them.⁷ But the political terrain for a carbon tax is treacherous.⁸ Even in the most prosperous of times, it’s far easier to pursue a public policy goal through regulation or tax credits and deductions than through an actual tax.

Short of a carbon tax, some economists would argue there are other, more efficient ways to reduce the use of fossil fuels in the production of energy than through RPS.⁹ Holding utilities to a carbon output standard, for example, in lieu of a renewable portfolio standard, would allow utilities to reduce carbon use through means other than increasing deployment of certain renewable technologies. One means of limiting carbon output is through a cap-and-trade mechanism, such as that employed by the EPA for years to limit SO2 emissions. Under cap and trade, utilities would fall subject to emission limits; those utilities exceeding their emission limits could buy allowances from other utilities with a surplus to spare. Legislation that would adopt cap and trade died in Congress in 2008¹⁰ but the EPA arguably has authority to establish a cap-and-trade regime by regulation.¹¹

The president recently directed the EPA to establish carbon emission limits for existing power plants.¹² But while it’s unclear whether the EPA would opt for a cap-and-trade approach, other means are available to implement carbon usage limits. Under a carbon use standard, utilities could promote greater energy conservation or greater use of energy efficiency technologies (such as LED lighting, superconductivity technologies to reduce line losses, etc.). Switching from coal to natural gas (retaining some reliance on new fossil-fueled generation) might also count toward meeting carbon use reduction targets. Improvements in efficiency and conservation might also serve. Many utilities have argued, however, that if they’re compensated based on their sales levels, they will have inadequate incentives to promote conservation and efficiency, as such measures would necessarily reduce their sales. Maximizing efficiencies, they maintain, will turn on whether the state regulators allow rate decoupling – mechanisms by which utilities are compensated both for the energy they sell and for achieving reductions in customer usage of electricity, particularly during peak periods.¹³ Decoupling can take a variety of forms. A number of state regulators have implemented policies permitting decoupling.¹⁴

This carbon output standard also would allow the utilities to devise the mix of renewable resources and other strategies that would reduce carbon use at the lowest cost. Does the flexibility and short term cost of this approach make proponents of a carbon output strategy the good guys? What if there was evidence that, given an increase in demand for renewable resources (which an RPS, by definition, produces), the cost curve for these resources would decline sharply and that an RPS would accelerate this development? Policymakers might then prefer to minimize reliance on gas-fired generation, even if it has a lower carbon impact than coal or oil. The accelerated development of lower-cost solar or wind resources, prompted by an RPS, might shorten the transition period from fossil-fired to carbon-free generation. Would opting for an RPS over a carbon output standard be a rational choice for policymakers in these circumstances? 

Wind vs. Solar: Taking Sides?

 Deciding what’s green and what isn’t is difficult enough. But deciding what will best promote clean energy may involve making choices even among similar green alternatives. Wind generation offers a case in point. Maryland recently passed legislation, long promoted by Governor O’Malley, to subsidize development of 200 MW of offshore wind capacity. Residential ratepayers will pay an additional $1.50 per month and businesses will pay a 1.5-percent surcharge per month.¹⁵ Will it promote the use of clean energy? Well, that depends.

Will the subsidy borne by ratepayers allow wind to develop even if solar is cheaper? If so, is that a green outcome? Will the cost of the legislation make it more difficult for legislators already facing budget constraints to call on ratepayers also to subsidize energy conservation or energy efficiency programs? If these programs are market-driven they will have to compete with wind resources. Could development of other, possibly more efficient green technologies be retarded as a result? Or will the wind subsidy serve to jumpstart offshore wind, increase economies of scale, lower costs and produce jobs in the long term, as the Governor hopes?¹⁶ How is this equation affected by the availability of low-cost natural gas produced from shale deposits? Will the subsidy be enough to achieve its intended result? 

In passing the legislation, Maryland lawmakers are betting that the benefits of potential job creation and lower carbon usage  will outweigh any a long-term detrimental consumer impact from higher rates. Lawmakers in other jurisdictions might reach different, but equally plausible conclusions. By asking the right questions, though, they improve the odds that they can reach clean energy goals without materially sacrificing efficiency. 

Even like sources of renewable energy can compete with each other, posing still other difficult policy questions for regulators.

Several years ago wind project developers and others in the Great Plains argued, vociferously, for a federal rate-making policy that would favor large-scale transmission projects to move wind power to the Northwest and the Northeast. The idea was to spread the cost of these new lines across entire regions, among utilities and their customers. Socializing the costs in this way, they insisted, would be necessary to get the transmission built and to make the wind resources economic. But regulators, legislators and others in the destination regions balked. These projects, they complained, were uneconomic. Subsidizing them would come at the expense of competing offshore wind projects that were closer to load and wouldn’t require the same investment in long-distance transmission. Not only did the idea of socializing large wind-related transmission projects stall, it prompted some legislators to propose bills that would have barred transmission funding that wasn’t tied to proportionate consumer benefits.¹⁷ And while the Federal Energy Regulatory Commission’s Order No. 1000, issued in 2011, did ease the way somewhat for broad allocation of new grid project costs, the Order expressly precludes allocation of the costs of interregional transmission projects without the consent of each of the affected planning regions.¹⁸

Offshore wind projects face additional obstacles. Like onshore wind, they need subsidies to survive, particularly given the drop in natural gas prices.¹⁹ But they also face environmental objections from landowners, naturalists and fisherman, as was the case with the Cape Wind project off the shore of Cape Cod. And they’re difficult to construct. So-called “jack-up” ships are needed to transport and install offshore wind turbines but the U.S. doesn’t have any, although a New Jersey company, Weeks Marine, hopes to have its first in use by 2014.²⁰ Still, it makes sense to pose the same questions when comparing offshore wind projects to other renewable, efficiency, and conservation alternatives, and when comparing such projects to more distant onshore wind projects.

Greens and Consumers: BFFs?

Just as the climate change debate can pit one technology against another, so too has it made adversaries of traditional allies, like environmentalists and consumer advocates. As environmentalists have championed wind power and the associated grid infrastructure, a number of environmental groups have come to favor transmission rate incentives for new transmission. Consumer advocates, meanwhile, have criticized FERC policies granting rate-of-return adders for new transmission as needlessly expensive rewards for doing what utilities were likely to do anyway and, in some cases for building transmission, they were already obligated by contract to construct.²¹ So who are the good guys in this skirmish? Consumer groups seem to be making headway in convincing environmentalists to look at costs and rates.  A handful of environmental groups recently have joined consumer advocates in counseling FERC against heeding utility calls to make its rate-of-return policies more generous.²² Whether environmental groups will find common cause with consumer interests on the shale gas revolution is still an open question.

Shale Gas: Bridge to Nowhere? 

Geologists and petroleum engineers have long known that shale formations, found throughout the United States and other parts of the world, hold large deposits of natural gas. But until the last decade and advances in the combined use of horizontal drilling and hydraulic fracturing these deposits have been economically unrecoverable. The availability of inexpensive natural gas supplies from shale – between 2003 and 2012 prices per Btu fell from $20 to $3 – has dramatically changed the energy landscape. It has, for the most part, made new coal-fired electric generation uneconomic²³ and if the price differential persists (oil is currently six times as expensive as natural gas),²⁴ it’s also likely to encourage more fuel switching by homeowners and vehicle operators from fuel oil and gasoline to natural gas. Most significant in terms of carbon impact, burning natural gas produces about half the CO₂ emissions of either oil or coal.

So what are the difficult questions consumer advocates, environmentalists, policy makers, regulators, and consumers should be asking about producing gas from shale? T. Boone Pickens has famously argued that moving from oil to natural gas for our transportation needs will provide a necessary bridge to a renewable-based energy system. Some environmental groups have warned that reliance on any fossil-fuel will instead prevent society from making the changes necessary to eliminate reliance on fossil fuels. Still others have warned that uncertainties about the safety of fracking – groundwater contamination, seismic disturbances, adequacy of water treatment facilities, warrant a halt to further development. Taking this view, the State of Vermont, which has only limited shale gas potential, enacted a moratorium on its development. 

The answer likely lies somewhere in between abandoning this fuel source and a full-speed-ahead approach. MIT economist Henry Jacoby sees big advantages to the economy over the next few decades from shale gas. The 2012 report he coauthored projects it creating thousands of jobs, lowering energy prices and driving “conventional coal out of the system.”²⁵“But,” he says, “it is so attractive that it threatens the other energy resources we ultimately will need.”²⁶ For one thing, lower energy costs will boost energy consumption, “yielding more emissions than if shale remained uneconomic.”²⁷ This effect won’t only make coal uneconomic, but it will make various forms of renewable energy and conservation efforts uneconomic as well. The MIT report estimates that, without other changes in policy, use of renewables to meet energy needs would never exceed RPS minimums as a result of the availability of natural gas from shale. And it would delay the date that carbon capture and storage would become economic for fifteen years. The good news, the report says, is that the lower energy costs from use of shale gas can help finance the transition to an energy economy not based on finite fossil fuels. And it offers this sage advice: Don’t let shale gas become a crutch instead of a bridge. 

Pipelines or Trains?

To borrow a phrase from the pre-digital era, journalists, consultants and others have spilled a lot of ink addressing the merits and downsides of the Keystone XL Pipeline, a project to bring Canadian oil from tar sands to US refineries in Texas and Louisiana.²⁸ The debate, if not the answer, is pretty straightforward. 

Keystone proponents argue that thousands of jobs in the U.S. and Canada will be lost if the pipeline isn’t built. Denying a permit, they add, won’t reduce carbon emissions from this source of oil nor prevent environmental degradation around the exploration site; the oil will be produced anyway and will simply be sold by the Canadians on the world market through other ports.²⁹ Canadian oil, they add, will reduce US reliance on energy from Venezuela and the Middle East. 

Opponents, by contrast, have maintained that extraction and transportation of the oil will itself pose environmental hazards and that, in any event, our government shouldn’t be endorsing the export of oil from tar sands because bitumen oil from these sources produces more greenhouse gases and other adverse environmental impacts than conventional oil.³⁰ Some voice concern that making this oil available domestically will slow expanded use of electric vehicles. Still others argue that the U.S. shouldn’t allow the transportation of oil, period. ³¹

Just as oil from Canadian tar sands promises to reduce U.S. reliance on oil imported from outside North America, so too have large oil finds in North Dakota made the US a potential exporter of fossil fuels.³² Lacking the pipeline capacity to market their North Dakota oil outside of the Great Plains and the Midwest, North Dakota oil producers have argued that the absence of a facility like Keystone is depressing the prices they receive because they can’t market their oil into the Southwest or Gulf coast states, where prices are higher.³³ This is the same concern voiced by Canadian bitumen oil producers.

Nearly lost in the Keystone controversy are two other developing phenomena – the increased use of rail transportation to move Canadian and North Dakota oil and the largely undiscussed development of a competing oil pipeline network by Enbridge and their combined potential impact on the environmental debate. These developments promise to render the Keystone debate – but not other environmental debates – irrelevant.

Over the last five years, rail carriers in the U.S. and Canada have greatly expanded their capacity to handle crude oil shipments. They do this by adding rail cars and running them more frequently, not by adding new tracks. The Railway Association of Canada has estimated that its members will ship up to 140,000 carloads of crude oil this year – compared to only 500 carloads in 2009.³⁴ U.S. shipments of oil by rail have jumped just as dramatically, from 9,500 carloads in 2008 to 233,811 carloads in 2012.³⁵

The significance of expanded rail shipments of oil is this: oil can and is being moved using existing rights of way. So issues such as wetland disturbances, stream crossings (the Keystone pipeline involve over 200 such crossings), scenic impacts and pipeline safety associated with citing new pipeline facilities, as well as the delays in obtaining governmental permission to operate new pipeline facilities, aren’t factors. 

All this is not to say that shipments of crude by rail pose no safety or environmental risks of their own. Oil spills from pipelines or offshore facilities can have widespread catastrophic consequences, like those resulting from BP’s offshore disaster in April 2010 or the Enbridge oil spill into the Kalamazoo River the same year. Spills from rail cars are more frequent– twice as frequent says the American Action Forum. Still, because oil is stored in individual tank cars, the overall damage is usually less severe. But that isn’t always the case. A recent rail car derailment in Quebec, for example, killed 40 people, spilled oil from over 70 tanker cars and forced 2000 people from their homes in the small town of Lac-Megantic – “the fourth freight train accident in Canada under investigation involving crude oil shipments since the beginning of the year.”³⁶

On one hand, the railroads can point correctly to a very good overall safety record – the American Association of Railroads boasts a 99.997 percent hazmat safe delivery rate. As the use of existing rail lines expands to move more oil, however, the chance of accidents necessarily increases. As one commenter put it, “The rail lines in North Dakota were not built for this kind of traffic.”³⁷

Canada’s Prime Minister has touted Keystone as an environmentally superior (and cheaper) alternative to shipping oil by rail.³⁸ Rail proponents argue that oil shipments by rail have less of an impact on the environment. To the extent proponents of domestic and Canadian oil are correct that, Keystone or not, their product will be sold somewhere, policy makers and even environmental advocates would benefit from considering whether shipments by rail might be more or less environmentally benign than shipments by pipeline. 

Also largely undiscussed in the popular press are the ambitious plans of another Canadian pipeline company, Enbridge, to expand the capacity of its existing network. In 2009 Enbridge completed construction of its Southern Access Pipeline, bringing 400,000 barrels per day of crude oil from Alberta’s tar sands deposits to U.S. refineries around Chicago. With additional pumping stations, Enbridge states that it will be able to transport 1.2 million barrels daily. And its Alberta Clipper line, finished in 2010, moves 450,000 barrels a day to the U.S., but can be expanded to transport 800,000. To put this in perspective, the expansion of capacity on these two Enbridge facilities is more than the entire 800,000 capacity of the Keystone XL pipeline.³⁹ These expansions, together with the expanded transportation of oil by rail would render the debate about whether to authorize Keystone academic. 

Water Use: A Wildcard

Coal-and gas-fired power plants produce CO₂, the latter significantly less than the former. Nuclear power plants produce no carbon emissions. But all of them produce power through a thermoelectric process – they all use steam heat to run turbines. And they use more water to cool the plants. Lots of it. So while the proponents of natural gas and nuclear power are right to tout the advantages they possess over coal as a source of carbon emissions, policymakers would be remiss to ignore the long-term implications of expanded thermoelectric power sources to produce electricity on our water resources. 

Writing in the Energy Law Journal several years ago, Prof.Benjamin Sovacool noted that the operations of thermoelectric plants in virtually every region of the country have had to be suspended or curtailed and that water use permits for still others have been denied outright because “they would deplete much needed freshwater for drinking and irrigation.” ⁴⁰ Between 1950 and 2000, he added, water use associated with conventional thermoelectric power plants increased fivefold. His point is that a shortage of water, not necessarily a concern about climate change, would drive utilities to replace thermoelectric power plants with renewable resources and increased conservation efforts. It’s a point that’s hard to dismiss out of hand. The Department of Energy estimates that 60 percent of existing coal-fired power plants are located in regions of “water stress.” Indeed, its July 11, 2013 report – U.S. Energy Sector Vulnerabilities to Climate Change and Extreme Weather –  warns that higher temperatures associated with global warming will only exacerbate the already serious water usage problem.⁴¹ Utilities, consumers and regulators are increasingly likely to take the water factor into account.

It’s All Good – and Bad

The notion that the United States can’t achieve either energy independence or effectively combat climate change without an all-of-the-above strategy is hardly novel. It embraces the proposition that America should pursue not only expansion of renewable energy production, but encourage conservation, energy efficiency, clean coal, nuclear power, electric storage, and natural gas exploration. But a little of this and a little of that isn’t an energy strategy. All-of-the-above is valuable only as a conclusion drawn from examining the interrelationship between various energy independence and climate change strategies – their short- and long-term impacts and both their political and economic feasibility. Whether, and if so, how and how much to subsidize one approach will invariably affect the success of other approaches.⁴²

Shale gas can make us energy independent. It can reduce carbon emissions by replacing coal and oil. But that doesn’t mean we shouldn’t foster renewables. After all, fossil fuel sources are finite and we’ll eventually need to rely on non-carbon based energy sources.

Wind is carbon-free, yet hasn’t increased its market penetration without RPS, tax credits, or other direct and indirect subsidies. But that doesn’t mean we should subsidize it at the expense of other renewable resources. Renewables, on the other hand, generally can reduce our carbon footprint, but if we subsidize them without caution, we may retard conservation efforts or improvements in energy efficiency. Coal is uneconomic compared to natural gas, is dirtier and produces higher CO₂ emissions, and carbon capture requirements would make it even less competitive with natural gas. But should we abandon efforts to find economic means to capture and store CO₂ and make coal clean because the payoff is far down the road and costly to pursue? Will water shortages impede the development of carbon capture technologies – which require water “to strip CO₂ from the flue gas?”⁴³ Nuclear power, too, can reduce carbon emissions, but is there a politically palatable solution to the waste storage problem that would allow greater reliance on nuclear power? And if the waste storage problem is solved, is there enough water available to support significant expansion of nuclear generation? Policymakers and industry participants interested in making the right decisions will grapple with all of these difficult questions.

Endnotes:

1. William D. Nordhaus, A Question of Balance: Weighing the Options on Global Warming Policies, Yale University Press 2008, Chapter 1.

2. Advocates for US energy independence, for example, frequently argue for improving energy efficiency and increased energy conservation as means to reduce reliance on imported fossil fuels. See, e.g., “A National Strategy for Energy Security” (2012), www.secureenergy.org, (accessed July 5, 2013). They’ve also advocated electrification of our transportation networks. Ronald E. Minsk, Sam P. Ori and Sabrina Howell, “Plugging Cars into the Grid: Why the Government  Should Make a Choice,” 30 Energy L. J. 317 (2009).

3. Twenty-nine states and the District of Columbia have adopted some form of renewable portfolio standard. Warren Leon, “The State of State Renewable Portfolio Standards,” p.1, CleanEnergy States Alliance, www.cleanenergystates.org, accessed July 23, 2013. The European Union has had a renewable portfolio standard since 2001.

4. California Senate Bill 2 (2011).

5. LCFC Cal. Code Regs. Tit. 17 § 95380. This, some out of state power producers have argued, not only raises questions of unfairness, but may violate the Constitution’s Commerce and Supremacy clauses. SeeRocky Mountain Farmers Union v. Goldstene, 719 F.Supp. 2d 1170 (E.D. Calif. 2010); Pacific Gas & Electric Co., 137 FERC ¶ 61,192 at P22 (2011); Joint Response of the Alliance for Retail Energy Markets and Retail Energy Supply Association in Support of Application for Rehearing of Cowlitz County PUD before the California Public Utilities Commission, Decision No. D11-12-052 (February 6, 2012). But also see Rocky Mountain Farmers Union v. Corey, No. 12-15131 (9th Cir. Sept. 18, 2013) (2-1 decision rejecting claim of facial Commerce Clause violation).

6. See David Coen, “Should Large Hydroelectric Plants be Treated as Renewable Resources, 32 Energy L.J. 541 (2011); Mary G. Powell, “Treatment of Large Hydropower as a Renewable Resource,” 32 Energy L.J. 553 (2011).

7. See, e.g., William D. Nordhaus, “Dealing with Climate Change:What Are the Major Options? (November 2008), www.eba-net.org (accessed July 5, 2013); William G. Gale, “Carbon Taxes as Part of the Fiscal Solution,” Brookings Institute, March, 2013.

8. See, e.g., Kate Ackley, “K Street Files: Manufacturers, Citing Job Losses, Opposed Carbon Tax,” Roll Call, Feb. 26, 2013.

9. See Karen Palmer and Dallas Burtraw, “Cost Effectiveness of Renewable
Electricity Policies,” Resources for the Future, January 2005.

10. Eric Pooley, “Why the Climate Bill Failed,” Time, June 9, 2008.

11. Massachusetts v EPA, 549 U.S. 497 (2007)

12. Evan Lehman and Christa Marshall, “Obama’s Climate Plan will Limit
Emissions from Power Plants and Heavy Trucks,” Scientific American, June 25, 2013.

13. David Boonin, “A Rate Design to Encourage Energy Efficiency and Reduce Revenue Requirements,” National Regulatory Research Institute ( July 2008), http://nrri.org, accessed July 8, 2013. The National Association of Regulatory Utility Commissioners defines decoupling as “a rate adjustment mechanism that separates (decouples) an electric or gas utility’s fixed cost recovery from the amount of electricity or gas it sells.” “Decoupling for Electric and Gas Utilities: Frequently Asked Questions,” 2007, www.naruc.org, accessed July 8, 2013.

14. Richard Sedano, “Decoupling Utility Sales from Revenues,” Report for
the Kentucky Public Service Commission, Regulatory Assistance Project, April 2009.

15. Aaron C. Davis, “O’Malley wins three-year battle over subsidy for offshore wind industry,” Washington Post, March 9, 2013. http://www.washingtonpost.com/local/md-politics/omalley-wins-three-year-..., Washington Post, March 9, 2013.

16. This is the theory discussed in a February 2013 study by the Brattle Group. Jurgen Weiss, Mark Sarro and Mark Berkman, “A Learning Investment-based Analysis of the Economic Potential for Offshore Wind: The Case of the United States,” www.brattlegroup.com (accessed July 13, 2013).

17. Peter Behr, “Battle Lines Harden Over New Transmission Policy for Renewables,” New York Times, Feb. 26, 2010, www.nytimes.com (accessed July 13, 2013).

18. FERC Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 400 (2011), (appeals pending), South Carolina Public Service Authority, et al. v. FERC,  Nos 12-1232 et al (D. C. Cir).

19. Earlier this year Congress extended the Production and Incentive tax credits to wind power producers. Without these breaks, many have argued that construction of new wind projects would slow to a trickle, supported only by RPS requirements in various states. “Blown Away: Wind Power is doing well, but it still relies on irregular and short-term subsidies,” The Economist, June 8, 2013.

20. Tim McDonnell, “Top 4 Reasons the US Still Doesn’t Have a Single Offshore Wind Turbine,” Climate Desk, February 28, 2013.

21. Policy Statement, Promoting Transmission Investment Through Pricing Reform, 141 FERC ¶ 61,129 (2012).

22. The Conservation Law Foundation, Climate + Energy Project, Earthjustice, Natural Resources Defense Council and Sierra Club’s Beyond Coal Campaign all joined in a July 12, 2013 letter from industrial electric users, municipal utilities, rural electric cooperatives and various state consumer advocate offices addressed to FERC and filed in FERC Docket No. RM13-18, Petition of WIRES for Statement of Policy and June 2013 Edison Electric Institute Report on Transmission Rates of Return on Equity.

23. Henry D. Jacoby, Francis M. O’Sullivan and Sergey Paltsev, “The Influence of Shale Gas on U.S. Energy and Environmental Policy,” Economics of Energy & Environmental Policy, Vol. 1 at 37-51 (2012)

24. Vicki Ekstrom, “A Shale Gas Revolution?” MIT News, Jan. 3, 2012.

25. Ibid., Jacoby.

26. Mason Inman, “Shale gas has transformed the U.S. Energy Landscape in the past several years—but may crowd out renewable energy and other ways of cutting greenhouse gas (GHG) emissions, a new study warns,” National Geographic News, Jan. 17, 2012.

27. MIT Report at 44.

28. Andrew Mayeda and Theophilos Argitis, “Harper Seeks to Build Keystone XL Support on U.S. Visit,” www.bloomberg.com (accessed July 8, 2013).

29. Tennile Tracy, “Pipeline vs. Train Safety in Focus After Quebec Incident,” Wall Street Journal, July 8, 2013.

30. Mayeda and Argitis, supra; Cameron Jeffries, “Unconventional Bridges over Troubled Water – Lessons to Be Learned from the Canadian Oil Sands as the United States Moves to Develop the Natural Gas of the Marcellus Shale Play,” 33 Energy L.J. 75 (2012).

31. “The answer is there’s no safe way to move this oil around,” said Eddie Scher, spokesman for the Sierra Club. “What we need to do is to get the hell off oil.” Stephen Mufson, “Canadian train disaster sharpens debate on oil transportation,” Washington Post, July 8, 2013.

32. “The Experts: How the U.S. Oil Boom Will Change the Markets and Geopolitics,” Wall Street Journal, March 27, 2013.

33. This is the same argument being made by the Canadian government and Canadian crude oil producers. Mayeda and Argitis, supra.

34. Crude by Rail, www.railcan.ca (accessed July 8, 2013)

35. Tennile Tracy, “Pipeline v. Train Safety in Focus After Quebec Accident,” Wall Street Journal, July 8, 2013.

36. Rob Gilles and Charmaine Noronha, “40 Still Missing in Deadly Canada Oil Train Crash,” (AP July 8, 2013)

37. Rusty Braziel, “Ridin the Bakken Slow Rail,” RBN Energy, February 1, 2012, www.rbnenergy.com (accessed July 14, 2012).

38. Mayeda and Argitis, supra, n. 16; “Rail Weighed Against Keystone XL,” May 17, 2013 (UPI) (www.upi.com) accessed July 8, 2013.

39. Lisa Song, “Canadian energy giant Enbridge is quietly building a 5,000-mile network of new and expanded pipelines that would achieve the same goal as the Keystone,” InsideClimate News, June 3, 2013, www.insideclimatenews.org (accessed July 14, 2013).

40. Benjamin Sovacool, “Running On Empty: The Electricity-Water Nexus And The U.S. Electric Utility Sector,” 30 Energy L. J. 11, 12 (2009).

41. “U.S. Energy Sector Vulnerabilities to Climate Change and Extreme Weather,” Department of Energy, July 11, 2013, p. 24.

42. The Treasury Department recently asked the National Academy of Sciences to look at one aspect of the issue, the conflicting impacts of various tax policies on greenhouse gas (GHG) emissions. The study found that the aggregate effect of existing oil and gas depletion allowances, home efficiency tax credits, nuclear decommissioning tax preferences and production tax credits for renewable energy on GHG emissions, though difficult to measure, has largely been a wash. William D. Nordhaus, Stephen A. Merrill and Paul T. Beaton, “Effects of U.S. Tax Policy on Greenhouse Gas Emissions,” National Research Council 2013.

43. July 11, 2013 DOE Report, supra, at p. 25.

Northern Indiana Public Service, the MISO member sandwiched between PJM’s Ohio territory and its noncontiguous Chicago outpost, feels particularly aggrieved by the failure of the MISO-PJM Joint Operating Agreement, approved by FERC in 2004, to facilitate cross-border grid projects to relieve constraints along the ragged and interlaced seam that separates the two regions.

In a complaint filed at FERC just last month, NIPSCO asked for relief from the omnipresent PJM power transfers across the gap between Ohio (in MISO) and Chicago (in PJM). These power flows lean on NIPSCO transmission lines, sometimes even forcing some of those lines to be opened, raising concerns over N-2 contingencies.

“That nothing has been built,” says NIPSCO, “is not due to lack of need.” (Complaint of No. Ind. Pub. Serv., FERC Dkt. EL13-88, filed Sept. 11, 2013.)

The need – for more transfer capability linking Ohio and Chicago – stems from PJM. But meeting that need means building lines within MISO. It’s the classic case of a cross-border problem that FERC had in mind when it added the interregional provisions to Order 1000.

The MISO-PJM JOA was supposed to solve such constraints, yet the odds appear stacked against any progress.

As NIPSCO explains, even if MISO were to identify a possible cross-border market efficiency grid project (MEP) in its own 2014 regional plan that would aid both regions, the project likely wouldn’t emerge from the JOA study process until 2015, and then would have to pass PJM’s own two-year intra-regional planning process, which wouldn’t be finished until the end of 2017. And that’s assuming no iterative modifications along the way, which would send everything back to the drawing board.

Says NIPSCO: “For the RTOs to cite the JOA as a ‘model of coordination’ … is unfounded in actual practice.”

“The process,” it adds, citing Shakespeare, “has been ‘full of sound and fury, signifying nothing.’”

For more information, see "Cross-Border Bargaining."

The Federal Energy Regulatory Commission’s enforcement of its anti-manipulation regulations has resulted in numerous actions with significant civil penalties and disgorgements of profits. While cases such as those involving Constellation, Barclays, and JPMorgan grab the news headlines, many other entities have settled investigations with FERC for multi-million dollar amounts that, although smaller by comparison, can still cause a significant hit to a company’s bottom line.

All companies engaging in energy trading – whether large or small, and whether directly regulated by FERC or not – must be mindful of this growing area of enforcement and should undertake actions to minimize enforcement risk. Many companies will, rightfully, view the risk of FERC enforcement proceedings as minimal, particularly if the company believes it runs a fully compliant operation. FERC, however, investigates many matters that ultimately do not result in civil penalties. Companies must thus be prepared to support and defend their actions even if they have done nothing wrong. In addition, because this enforcement program is its relative infancy and has not been meaningfully tested in the courts, it cannot be understated that there are few bright lines that distinguish creative and aggressive trading from market manipulation.

In this regard, companies can undertake several straightforward yet effective steps to minimize the likelihood of an investigation and reduce the risk of an adverse outcome in the end. Any of these suggestions, however, should be discussed with counsel before implementation.

Rule 1– An Ounce of Prevention Is Worth Many Pounds of Cure

FERC has stated that companies should maintain a “culture of compliance.” To most, this means that executives must lead by example and instill appropriate values in their employees. But more is required than published codes of conduct and statements of executives to instill fully a culture of compliance. In this regard, an ounce of prevention in instilling a true culture of compliance is worth many pounds of cure. But instilling a true culture of compliance requires more than just management say-so. It requires substantive training, management presence, and willingness of the company to undertake potentially unpopular actions (including appropriate disciplinary actions) when necessary to ensure compliance.

One effective means of instilling a culture of compliance is regular, substantive, and meaningful training of employees with regards to compliance matters. Each session need not be extensive. Indeed, employees often learn better in shorter increments rather than in day-long sessions. Most companies have regular department meetings and brief compliance training sessions. These gatherings can be used as a place to reinforce the “culture of compliance” message and convey important information in a timely manner. Certain lessons likely warrant repeating at these sessions (e.g.,“Routinely losing money on one type of transaction will likely raise FERC’s eyebrows, so keep a close eye on your P&L”), but the balance of the discussion should change subject regularly, and focus on new developments when they happen, in order to keep people’s attention. Training is critical because many energy traders come from backgrounds outside the regulated world of wholesale power and have little to no exposure to FERC.

Executive or senior management attendance and involvement at such training can be valuable as well. Not only does it reinforce that the culture of compliance comes from the top, but it provides a forum for employees to express concerns and ideas, and for management to provide guidance that is consistent with the overall goals and practices of the company. In this vein, while many companies have “compliance hotlines” to report concerns to management, some have also adopted “no retaliation” policies to further encourage reporting. It may be appropriate, however, to limit any such policies so that deliberate or reckless acts have real adverse consequences for the people involved.

Rule 2– Be Present, Be Vigilant, Be Proactive

Management proclamations and training in the culture of compliance can only go so far. People forget things and “when the cat is away, the mice [often] will play.” Sometimes the best defense is a good offense, which, in the enforcement context, means oversight and proactive efforts to identify problems.

Out of sight means out of mind. While a poster stating a company’s code of conduct is a useful reminder, it is no substitute for compliance personnel being present. Their presence not only reminds employees that their actions will be scrutinized, but, on a more positive note, it provides employees an easy opportunity to ask questions. This two-way communication is critical to establishing an effective compliance program. Where compliance personnel come from the in-house legal team, management may want them to sit in the legal department. But management should also consider giving them a second office, or perhaps even better, a desk on the trading floor so that they can spend part of their time shoulder-to-shoulder with traders.

Presence means little, however, if personnel – traders and management alike – are not vigilant. Everyone must keep open eyes and ears toward what is happening. Willful ignorance might seem inviting, but it is unlikely to serve a company well in the long term. Questions should be asked, but without accusation. Traders should understand that this is not an indictment but merely part of the process of ensuring compliance. If management or other traders have questions about certain actions, FERC will likely as well. It is better to understand the actions sooner rather than later.

Vigilance often involves proactive efforts by companies. Management should not wait for employees or FERC to identify concerns. Often, that will come too late and well after questionable conduct has occurred. Further, employees might not have access to the information about other employees needed to connect the dots and identify an issue. Management will have the data and should mine it for issues. While most companies investigate outsized losses, they should also investigate outsized wins to ensure that they were attained in a compliant manner. If companies record IMs or other communications, they might also want to spot check them or search for words that could raise compliance concerns.

Rule 3– Document Thoroughly and Thoughtfully

A paper trail often can be the best defense in the face of an investigation. Actions and reasons for actions are often forgotten with time, and FERC may ask questions many months or even years after trades took place. In the rapid world of trading, memories can get fuzzy quickly and employees who hold key information can leave. Documenting events as they occur can be useful in answering regulators’ questions.

While documenting can be helpful in the long run, it can also be a double-edged sword. However, having no document policy is unlikely to help anyone. While there is no one-size-fits-all policy, merely having a document policy may be the most important step. The advice of counsel with regard to the development of a document policy is critical, particularly as to the best means to preserving attorney-client privilege, where available.

One area of documentation that should not be controversial, however, is the need to keep business records – including trading data – in an orderly manner. Sloppy recordkeeping might be perceived as general sloppiness and a lack of attention to compliance obligations.

Rule 4– Know Thy Regulator

A regulator’s job is to enforce the law. Companies and employees must understand and respect that fact. The regulator’s job includes looking at actions skeptically. Arguing with a police officer who asked “why were you speeding” accomplishes little. Getting defensive with regulators looking into trading activities accomplishes little as well (and might make regulators think there is something to hide). Be prepared to defend actions, but do not get defensive.

Companies should look at their own trading activities with a skeptical eye as well. Ask “How would this look to FERC if viewed in the worst way possible?” Certain perfectly compliant transactions might look inappropriate under certain circumstances or if only some of the data is seen. Defending an investigation into perfectly legal action can be costly even if the action is dismissed. Thus it may be better to avoid activities that, although legal, might appear to the regulator to be problematic and result in an investigation.

The body of law surrounding FERC enforcement of energy trading is still in its infancy as compared to that of other federal agencies. As a result, almost every FERC enforcement order provides useful study. While some issuances might seem to be “more of the same,” there are often subtleties that can indicate how FERC’s thinking and policies are evolving. Companies should, of course, stay knowledgeable about the facts underlying new orders but should also look for these subtleties as they can be invaluable in understanding FERC and avoiding, or shortening, investigations.

While there is no one-size-fits-all for a compliance program, certain common elements exist among many effective compliance programs – the need for a true culture of compliance, active oversight of trading operations, a balance documentation policy, and an understanding of regulators’ policies. Even the best compliance program is no guarantee against an investigation, but it will likely minimize the likelihood of the investigation and any adverse consequences stemming from it.

ABOUT THE AUTHOR
Jeffrey M. Jakubiak (Jeffrey.Jakubiak@troutmansanders.com) is a partner in the New York City and Washington, DC offices of Troutman Sanders LLP. His practice focuses on FERC regulation of energy trading and electric-asset transactions. This article does not constitute legal advice nor does it establish an attorney-client relationship between the author and the reader. The opinions expressed in this article are the author’s own and do not necessarily reflect of the views of Troutman Sanders LLP or its clients.

By the term “anomaly,” we don’t mean “Armageddon.” With the government shutdown recently lifted as this issue was going to press, we offer no prediction on how the continued sense of budget uncertainty and risk of future U.S. credit default might affect utility rate making and cost recovery.

Rather, this year’s annual survey of retail rate case orders and the rates of return on common equity (ROE) authorized therein prompts a question much less worrisome, though no less urgent:

Should the historically low interest rates of the past several years require a haircut to the ROEs authorized for regulated electric and natural gas distribution utilities in rate cases now being decided, or does this credit climate represent an historical anomaly – one that should call into question whether today’s rate-making methods, which for years have remained largely unchanged, are still producing the right answers?

Here, as in every survey, we provide data from all major electric and natural gas rate case orders. But we also take a look at three new rate case opinions from the past year that address the question of Anomaly vs. Normal: one from Connecticut, one from Alabama, and one from the Federal Energy Regulatory Commission (FERC).

Rate-Making Methods

Over the past several years, the Fortnightly’s annual November rate case survey has revealed a continued reliance on the discounted cash flow (DCF) model as the touchstone for ROE determinations. Other methodologies are considered, however, and in the end most commissions inform us that the process is as much art as science, with the goal being to balance the evidence and apply sound judgment to produce a fair rate of return.

Wrangling over technical aspects of financial modeling comprises the lion’s share of the record, but the essential question remains the same: what figure will give the utility a fair chance to attract equity capital?

Under traditional rate-base and rate-of-return regulation, investors are thought entitled to earn a return that falls within a “zone of reasonableness.” And as further defined by federal and state courts, a fair rate is one that is sufficient to attract capital on reasonable terms and high enough to enable the utility to maintain its financial integrity.

One way regulators have approached the question is to begin by looking at how much an investor would earn by purchasing a so-called risk free investment, generally measured as the interest rate on U.S. Treasury bills. Rates for these instruments have remained low for several years, and encouraged to stay low by a Federal Reserve dedicated to easing credit and boosting the economy.

This climate has led those seeking higher ROE awards to argue that the current interest rate trend is anomalous – that recent indications suggest the Fed will soon rework these near-zero coupon rates and ratchet them upwards, possibly to tamp down any inflationary pressures as the economy begins to recover from the Great Recession.

Three August Viewpoints

In August, in a widely watched case, FERC Administrative Law Judge Michael Cianci chose to ignore claims that the current interest rate climate
climate is somehow anomalous.

He rejected expressly any argument that “these unusual financial and economic times” must render the traditional ROE analysis obsolete, but conceded that on appeal the full commission would be “free to consider any policy decisions it believes are warranted.” Martha Coakley v. Bangor Hydro-Elec. Co. et al., Docket No. EL11-66-001, Aug. 6, 2013, 144 FERC ¶63,012, at ¶549.

The judge ruled that FERC precedent required strict adherence to results of the DCF method of financial modeling in setting the base ROE. That finding led the judge to rule that the current 11.4-percent base-level ROE (shorn of all incentive adders) that has long applied to network transmission service provided by ISO New England across the six-state region over lines owned by New England’s electric transmission owners (NETO) is unreasonable and unlawful under existing capital market conditions – i.e., declining yields for Treasury and public utility bonds. (For more detail on the case, see “Investor Sequester,” this column, June 2013, http://www.fortnightly.com/fortnightly/2013/06/investor-sequester.) 

But if lower ROEs are indeed the new normal, what might we expect in terms of utility growth?

Often, claims on whether a rate is high enough to attract and hold investors over the long term are simply left to stand on their own. Or, they are sometimes buttressed only by statements regarding the effect on future credit ratings an ROE award might make. Accordingly, it’s interesting to note that Judge Cianci in the FERC proceeding assigned “moderate probative value” (144 FERC ¶63,012 at ¶576) to a study purporting to show that if ROE is set substantially below 10 percent for long periods of time it could negatively affect future investment in NETOs. 

On the other hand, Fortnightly Editor Michael Burr reported in last month’s issue that regulated utilities succeeded in raising near-historic amounts of debt capital during the period since 2008, with such success attributed at least in part to favorable regulatory treatment at the state level. (See, “Five Years Later,” October 2013.)

In another case handed down in August, involving United Illuminating, the Connecticut Public Utilities Regulatory Authority (PURA) also reviewed conflicting arguments on whether historically low Treasury bond rates would remain, or would be pushed higher soon by evolving Fed policy. Connecticut decided, for the most part, that low interest rates would continue for the foreseeable future, justifying an authorized ROE of 9.15 percent – up from the prior rate of 8.75 percent, but lower than UI’s request of 10.25 percent. (United Illum. Co., Conn.PURA Docket No. 13-01-19, Aug. 14, 2013.)

In other words, the lesson from Connecticut was mixed.

On one hand, the PURA warned us not to assume that continued low interest rates would guarantee the company’s continued positive financial performance. Such “presupposition is inappropriate,” it noted. Yet the PURA sided with the state’s Office of Consumer Advocate that achieving a 6.5-percent national unemployment rate – a benchmark that could trigger a new, less expansive monetary policy from the Fed – appeared unlikely in the near future.

A somewhat contrary view comes from the Alabama Public Service Commission in a third decision issued in August. In a case involving Alabama Power, the PSC rejected allegations that current economic conditions (i.e., low interest rates) indicate reduced expectations by utility stock investors. (Alabama Pwr. Co., Ala.PSC Docket Nos. 18117, 18415, Aug. 21 2013.)

The PSC rejected claims that the utility’s then-current authorized ROE range of 13 to 14 percent was too high given the persistently low interest rates seen in the market. It rejected a 10-percent compromise ROE that was proposed by consumer advocates and based on traditional analyses using the DCF and CAPM (capital asset pricing model) methods.

Instead, the PSC found the current low interest rate climate anomalous, as argued by the utility.

The commission added that while a consumer advocate witness had noted a downward trend in allowed returns, he had neglected to acknowledge an offsetting increase in common equity ratios among utilities over the same period.

As the PSC noted, the consumer advocate’s argument was based in part on “an unsubstantiated conclusion that the current environment of ‘artificially low’ interest rates represents normal conditions for the foreseeable future.”

Download Figure 1: 2013 Rate Case Study in pdf format here.

Notes to the figure:

* Settlement agreement ROE not specified.

NA = not available

1. Utility operates under a rate stabilization and equalization plan – an alternative rate-making mechanism that provides for periodic automatic adjustments to rates to maintain ROE within a specified range.

2. Equity ratio capped at 55 percent. Down from 60 percent per order dated 12/01/2009.

3. Order establishing return on equity, return on rate base and resulting reductions in revenue requirement for the state’s major energy utilities.

4. On March 21, 2013, commission issued an order approving a settlement agreement resolving Phase II issues setting benchmark indexes for subsequent adjustments. Re: Southern California Edison Co., D.13-03-015, 304 PUR4th 296 (2013).

5. General rate case proceeding. Findings limited to revenue requirement issues. ROE considered in separate generic docket, D.12-12-034, as shown.

6. General rate case proceeding. Stipulated revenue requirement shown.

7. Allowed ROE reflects reduction from stipulated figure of 10 percent. Reduction composed of 0.5 percent attributed to lower interest rates and 0.5 percent due to over-curtailment of renewable energy by utility.

8. Annual formula rate plan update.

9. Initial order issued 2/3/13. Re: Indiana Michigan Power Co., 303 PUR4th 384 (2013). Figures shown reflect subsequent updates.

10. Company operates under earnings sharing rate plan.

11. Utility operates under formula rate plan. Figure shown is midpoint of earnings range approved by the commission.

12. Commission finds no significant factor that would justify a radical departure from 9.31 percent ROE granted in prior rate order dated 7/20/12, as suggested by the utility.

13. Pursuant to settlement agreement submitted in period evaluation proceeding under the utility’s rate regulation adjustment plan.

14. ROE not stated. Commission finds overall rate of return of 7.39 percent, given its benchmark range of 8 to 26 percent for ROE under its formula rate plan.

15. Company agrees to eliminate its existing infrastructure system replacement surcharge and roll amounts collected into base rates. Surcharge reset to zero.

16. Figure shown as stated in final order on rehearing. Original order set ROE at 9.8 percent for Southern Nevada and 9.2 percent for Northern Nevada.

17. Docket concerning application for approval of a four-year infrastructure improvement program. Increase shown is total approved cost exclusive of allowance for funds used during construction (AFUDC). ROE on capital investment set at 9.75 percent for ratemaking purposes. Separate AFUDC carrying cost rate set at 6.9 percent.

18. Order extending terms of current rate plan for two additional years. Earnings sharing (80/20; ratepayer/company) begins when earnings reach figure shown.

19. Merger application resulted in two-year rate freeze with no change in allowed ROE. Earnings sharing threshold reduced from 10.5 percent to 10 percent.

20. Earnings sharing mechanism. 50/50 sharing begins when earnings reach ROE shown.

21. Distribution service only.

22. Revenue deficit calculated per demonstrated actual earnings of 9.32 percent.

23. Benchmark ROE under utility’s performance-based rate change plan.

24. No change in base rates indicated per annual earnings review.

25. Parties to settlement agreement unable to agree on specific values for cost of capital components. Figure shown listed as “notational value.”

26. Approved in rate case decided in 2004.

27. No previous PUC-approved ROE. Company was recently formed to provide transmission for wind powered electric facilities.

28. Two-step increase: $37 million on 5/1/13; and $13.8 million on 9/1/13.

29. A single two-step increase: $100 million on 10/12/12; $54 million on 9/1/13.

30. Major portion of utility’s request includes claims related to under-recovery of purchased power costs. In addition to base rate increase shown, utility is authorized to implement a surcharge to recover $239,046 for payment of arrearages owed to power supplier.

31. Total revenue increase. Application filed in two steps. Initial increase of $32 million effective 10/22/12 and a second of $18 million effective 10/1/13.

The design framework for a California Independent System Operator (ISO) energy imbalance market (EIM) received approval from the ISO board of governors. The EIM will allow western grid operators, known as “balancing authorities”, to voluntarily participate in a real-time energy market that enhances grid reliability and responsiveness, effectively integrates renewable power and saves wholesale energy costs. The ISO’s first EIM partner, PacifiCorp, has been working with the ISO to prepare for implementing the market expected to go live on October 1, 2014. The EIM design will enhance the Federal Energy Regulatory Commission (FERC) Order No. 764, which fosters better integration of renewables within electric regions. The ISO is already on course to implement Order No. 764 market changes in the spring of 2014. The vote by the board also authorizes ISO management to file EIM-enabling proposed tariff changes with FERC.

Williams Partners received Federal Energy Regulatory Commission (FERC) approval to expand Transco, the nation’s largest natural gas pipeline system, to provide service to a new, gas-fired, power-generation plant in Virginia. The approximately $300 million Transco Virginia Southside Expansion is designed to provide 270,000 dekatherms per day (dth/d) of incremental transportation capacity in Virginia and North Carolina by September 2015. Of the total expanded capacity, more than 90 percent will serve Dominion Virginia Power’s new power plant; the remainder will serve Piedmont Natural Gas Company’s local-distribution business in North Carolina. The Virginia Southside Expansion is part of $2.2 billion of Transco growth projects that Williams Partners has previously announced it plans to bring into service between 2013 and 2017.

Recently I shared a conversation with a senior utility executive at an industry conference. We talked about major forces driving changes in the utility industry – i.e., cheap gas, EPA regulations, cybersecurity imperatives, renewables and distributed energy resources, etc. – and he offered up the following comment:

“It’s a great time to get into the utility industry, and a great time to get out of it.”

By “get out of it,” he was referring to the fact that he’s nearing retirement, and doesn’t envy the ranks of industry executives who will be moving into leadership positions over the next few years. He observed that utility industry leaders – and policymakers – are entering unfamiliar territory, on everything from resource planning to alternative ratemaking. Often that leads to conflict with customers and other stakeholders, as the industry attempts to transition from yesterday’s status quo to tomorrow’s new reality. 

None of these challenges will be easy to resolve, and they’re coming just as Baby Boomers are retiring and taking their wisdom and experience out of the board room and onto the golf course. The next crop of leaders will be tasked to resolve a complex array of interdependent problems – and to do so without unfairly burdening or rewarding anybody. 

A tall order, to be sure.

At the same time, the executive observed that the industry’s new leaders might find today’s challenges somewhat less discomfiting. Viewed from the perspective of someone now entering the executive suite, the current landscape offers unprecedented opportunities for influencing fundamental change in the industry. For new leaders who are eager to make a difference in the world, he said, we are now entering the best of times. 

But that doesn’t mean the times will be easy.

Just Reasonable

In the federal policy realm, the Federal Power Act established the primary mandates that are supposed to guide the actions of America’s utility regulators – e.g., the Federal Energy Regulatory Commission (FERC). Among the marching orders that Congress provided in the FPA, the most fundamental is the requirement for regulatory mechanisms to produce rates that are “just and reasonable.” 

To an untutored eye, such a mandate might seem straightforward. In reality, however, those words – “just and reasonable” – represent the fundamental subject of ongoing, rancorous conflict among a wide range of stakeholders. 

For example, this issue of Fortnightly includes a range of perspectives on one major battleground in that debate – namely, how effectively are the organized capacity markets (namely those in PJM, ISO New England, and the New York ISO) producing just and reasonable rates in the generation and transmission parts of the business? And what structural changes will be most likely to produce them in the future?

Depending on whom you ask, competition in organized markets for energy, capacity, and demand-side resources has served to push wholesale prices down lower than they would be otherwise – and lower than they are in comparable locations that lack organized markets; or, alternatively, the markets have created perverse incentives that deter new plant construction, and set the stage for a mortal disaster with supply shortages and price spikes. 

Still others contend that instead of creating a level playing field for healthy competition, the organized markets have simply institutionalized an even bigger monopoly system than that of the vertically integrated utility, marginalizing options that don’t serve the interests of transmission-owning ISO members across entire regions.

The fact is, we can’t know for certain whether ISO-RTOs are actually producing just and reasonable rates or attracting investments sufficient to keep them that way in the future. That’s partly because it’s so difficult to test anything concrete about the effects of dynamic market forces; the landscape keeps shifting around, making assumptions obsolete. In part it’s also because we have no valid basis for comparison; we’ll never know what rates and resource additions would be like in the Northeastern states if the ISOs didn’t exist. We can compare and contrast ISO states and non-ISO states, but that won’t prove anything; the factors are too complex, and the outcomes are open to interpretation. 

Mostly, however, the uncertainty arises from the simple fact that not everyone agrees on what “just and reasonable” rates actually look like. Whether that’s a problem or an opportunity depends on one’s perspective.

Reasonably Just

In the good-old days – before deregulation and renewable portfolio standards, before shale gas and solar rooftops – the process of setting “just and reasonable” rates was relatively straightforward. Vertically integrated utilities invested in the assets necessary to provide safe, reliable, affordable service, and regulators granted cost recovery – to the degree they agreed such investments were necessary. 

That was then; this is now. For better or worse, during the past 40 years policymakers have been tinkering with the parameters for providing utility service, toward a variety of goals – from supporting coal-mining jobs to improving energy efficiency. Some of these adjustments are reflected in wholesale power prices, but many of them aren’t. In fact, in some parts of the country, wholesale power charges account for less than half of customers’ monthly bills; wires costs and various surcharges have tipped the balance away from generation and toward delivery and service. And if current trends continue, that balance will tip further as utilities pass along the costs of investments in new T&D infrastructure – and as utilities seek to ensure all customers bear their share of utilities’ fixed costs, even as their kilowatt-hour purchases decline with growing conservation and distributed generation. 

In this context, who can say for sure whether markets are producing just and reasonable rates? If the organized markets produce reasonable wholesale rates, but wires costs and various surcharges spiral out of control, then the industry will have failed to meet the just-and-reasonable standard. By the same token, if organized markets stumble and customers suffer prolonged shortages and price spikes – as some doomsayers predict they will – then the industry’s leaders will have no choice but to reconsider their entire strategy for meeting the FPA mandate. 

It’s tempting to imagine that such failures would force the industry to abandon organized markets and complex incentive ratemaking, and return to a simpler time of vertical integration and quid-pro-quo regulation. What’s far more likely, however, is that incoming leaders will do their level best to address the new realities of policy goals and technology options, and they’ll find new ways of meeting the just-and-reasonable mandate – while pursuing the opportunities that emerge during a time of dramatic change.

The 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank or the Act)¹ amended the Commodity Exchange Act (CEA)² and greatly expanded the jurisdiction of the Commodity Futures Trading Commission (CFTC or the commission) over financial instruments used in energy transactions. At the time of its enactment, there was great uncertainty about how Dodd-Frank and the related CFTC-implementing regulations would affect retail electric utilities and local natural gas distribution companies. Even after several years of CFTC clarification, the CEA’s applicability to specific retail utility transactions requires constant vigilance by utilities. 

Retail utilities and large end-users who purchase energy often enter into associated financial transactions that shift the price risk of the energy from the utility purchaser to a third party. Implementation of Dodd-Frank potentially exposed retail utilities and other energy purchasers to the same regulatory burden as large financial institutions³ when such entities enter into financial and physical commodity transactions.⁴

Over the past few years, the CFTC has issued a whole mosaic of interrelated implementing rules.⁵ As part of this mosaic, the CFTC has issued several rules and interpretive guidance notifications that clarify the extent to which it will regulate the activities of electric and natural gas utilities (and other end-users). In large part, retail utilities can rely on these labyrinthian exemptions and no-action determinations to avoid the full regulatory burdens of Dodd-Frank. However, the CFTC’s general anti-fraud and anti-manipulation authority, and scienter-based prohibitions under CEA continue to apply.⁶ Moreover, the CEA-exemptions that apply to retail utilities generally require case-by-case scrutiny, because they are determined by the facts and circumstances of each transaction. 

Unintended Targets

Before the individual tiles in the Dodd-Frank mosaic can be fully interpreted as applicable to utilities, the overarching intent of the Act must be understood. Electric and natural gas utilities provide utility services to retail customers in accordance with the rates and conditions approved by state regulatory commissions. While utilities purchase natural gas and electricity for physical delivery, they also use financial tools to hedge risks associated with providing retail service.⁷ In other words, most utilities are end-users, and they use financial instruments to mitigate the price volatility of the commodities needed to provide service to customers and mitigate the effect of potential commodity price fluctuations on customers.⁸ The financial instruments include exchange traded futures contracts and energy derivatives.⁹

Prior to Dodd-Frank, financial instruments associated with a physical energy transaction and used by a regulated purchaser to hedge its price risk were largely unregulated by the CFTC. Moreover, except for the CEA’s anti-manipulation provisions, the CFTC expressly exempted contracts for the purchase and sale of crude oil, condensates, natural gas, and natural gas liquids.¹⁰ Specifically, certain oil, natural gas, and electricity related transactions were primarily subject to oversight by the Federal Energy Regulatory Commission (FERC) and the various states, as applicable.¹¹ The CFTC didn’t actively regulate the energy transactions that were subject to FERC’s authority. However, the CFTC’s jurisdiction to prohibit manipulation of the market price of any commodity in interstate commerce or for future delivery on or subject to the rules of any contract market, continued to apply.¹²

During the Congressional debate and enactment of Dodd-Frank, one of the major concerns for electric and natural gas utilities was whether their activities would be subject to the same regulatory burdens applicable to large banks or financial institutions, or whether their status as end-users would lighten the regulatory load.¹³ This concern continued during the CFTC rulemaking and implementation process. In other words, prior to the issuance of the CFTC’s implementing regulations, the pending question was whether utilities could enter into transactions in order to provide utility service in the same manner as during the pre-Dodd-Frank period or would these traditional endeavors be regulated in some way by the commission.¹⁴

While the Act doesn’t specifically exempt electric and natural gas utility operation from the regulatory burdens of the revised CEA, some legislators did support the concept that utilities wouldn’t be subject to the same regulatory burdens as a financial institution. In June 2010, prior to Dodd-Frank being signed into law, Senators Dodd and Lincoln sent a letter to Representatives Frank and Peterson explaining that electric and gas utilities weren’t the intended target of the then-pending legislation.¹⁵ The Dodd-Lincoln Letter explained that the law was intended to preserve the ability of end-users to enter into hedging transactions to mitigate the risk of market volatility. Moreover, the intent of the bill, according to the senators, wasn’t to regulate end-users such as electric and gas utilities that purchase commodities to provide service to customers and use swaps to manage risk associated with their business. 

The senators encouraged the CFTC to exclude from the definition of swaps any sale of a nonfinancial commodity for deferred delivery when the transaction is intended to be physically settled, even where the parties could agree to book-out the delivery obligation under such a forward contract. For example, power purchase agreements or natural gas supply contracts that provided for delivery at a later date, but that also permitted the potential for a booking out of the delivery obligation, were, according to the senators, to be exempt from the swap definitions. However, since the Dodd-Lincoln Letter itself didn’t carry the full force of law – and it was left to the CFTC to interpret the text of the revised CEA and determine what utility activities would be regulated under the forthcoming regulations – many of the concerns raised by the senators were arguably muddled in the translation of the requirements under Dodd-Frank from statute to regulation.

Threshold Regulatory Questions

In large part, the CFTC, through the rulemaking and the statutory interpretation process, and via no-action letters, has attempted to stay true to the intent of Dodd-Frank, as embodied in the Dodd-Lincoln Letter. However, uncertainties and pitfalls remain that could result in electric and natural gas utilities being subject to the full regulatory burden of Dodd-Frank. While the CFTC’s actions have provided certain exemptions applicable to electric and natural gas utilities that generally protect utilities’ historic activities from burdensome regulation, exemption isn’t guaranteed. Utilities must be aware of the pathways that might lead to their required compliance with all of the regulatory burdens of Dodd-Frank. 

There are two critical and integrated inquiries that utilities must undertake in order to determine if full compliance with all the requirements of Dodd-Frank are necessary or whether any existing exemptions are applicable: Is the transaction being entered into a swap? And is the utility a swap dealer or major swap participant?

The answers to these questions will determine whether, and to what extent, an exemption applies or whether a utility must comply with all applicable Dodd-Frank requirements. Therefore, the critical tiles in the mosaic that must be examined are the CFTC’s interpretation of the definition of “swap” and its separate interpretation of the definitions of “swap dealer” and “major swap participant.”

Section 721 of Dodd-Frank¹⁶ amended the CEA by adding definitions for the term “swap,”¹⁷“swap dealer,”¹⁸ and “major swap participant,”¹⁹ among others. The definitions in the Act are quite broad and Section 712 Dodd-Frank required that the CFTC, in conjunction with other agencies, further clarify and refine the relevant definitions,²⁰ therefore the CFTC had the authority to clarify what are and are not considered swaps.

In the revised CEA a swap is defined, inter alia, as any transaction that contains optionality related to the purchase or sale of commodities or property of any kind or that provides for any purchase, sale, or delivery that is dependent on the contingent on the occurrence of an event.²¹ Importantly, however a swap isn’t “any sale of a nonfinancial commodity or security for deferred shipment or delivery, so long as the transaction is intended to be physically settled.”²² On the face of it, a broad interpretation of the statutory Dodd-Frank swap definition could be interpreted to include certain power purchase agreements, full requirements contracts, and agreements that could be booked-out or financially settled. The statutory definition of a swap, the CFTC’s interpretation of the definition, and the related exclusions are critical because Dodd-Frank makes it unlawful to enter into a swap without complying with the full regulatory requirements of the Act. As such, how the CFTC interpreted the swap definition in the Act was essential in determining to what extent energy related transaction would be subject to all of the regulatory requirements of the revised CEA.

Nonfinancial Commodities and Forward Contracts

In August 2012, the CFTC published a Final Rule defining “swap.” The rule clarified the extent to which “nonfinancial commodities forward contracts” are included in the swap definition under Dodd-Frank.²³ An example of a nonfinancial commodities forward contract is a contract between an electric utility and a marketer that includes a present price to be paid by the utility but defers the marketer’s delivery of power until a future time. 

A critical question for utilities was how the CFTC would interpret the term “nonfinancial commodity” as it’s used in the blanket exemption from the swap definition in the revised CEA. In short, the CFTC generally determined that the term “nonfinancial commodity” means a commodity that can be physically delivered.²⁴ However, certain intangible commodities that can be physically delivered also qualify as nonfinancial commodities (such as an emission allowance) if ownership of the commodity can be conveyed and the commodity can be consumed.²⁵

The basis of the CFTC interpretation of what nonfinancial commodities meet the exclusion from the swap definition is consistent with CFTC precedent regarding the forward contract exclusion. This approach generally excluded from regulation transactions involving market participants that regularly make or take delivery of the commodity at issue in the ordinary course of business.²⁶ In short, the CFTC stated that the forward exclusion in nonfinancial commodities would be interpreted by the commission consistent with its historical interpretation of the existing forward exclusion with respect to futures contracts.²⁷ For the forward contract exclusion to apply, a transaction must include a nonfinancial commodity, be for future or deferred delivery, and the parties intend for the transaction to be physically settled.²⁸ This determination by the CFTC went a long way in implementing the intent embodied in the Dodd-Lincoln Letter. As a practical matter, and as applicable to utilities, this interpretation means that supply agreements, such as full requirements contracts to meet provider of last resort or default service obligations, generally would meet the forward contract exclusion to the swap definition and wouldn’t be regulated by the CFTC. As the CFTC explained “any variability in delivery amounts under the contract appears to be driven directly by the buyer’s commercial requirements and is not dependent upon the exercise of any commodity option by the contracting parties.”²⁹

Furthermore, the CFTC’s treatment of book-outs with regard to the forward exclusion from the definition of “future delivery”, i.e., the Brent Interpretation,³⁰ would also be applicable to the forward exclusion from the swap definition for nonfinancial commodities under Dodd-Frank.³¹ Under the Brent Interpretation, which is applicable to transactions entered into between commercial participants in connection with their business,³² counterparties with offsetting positions may forego delivery and instead negotiate payment-of-differences pursuant to a separate, individually negotiated cancellation agreement referred to as a “book-out.” 

Because of the application of the Brent Interpretation by the CFTC to nonfinancial commodities, the commission withdrew the 1993 Energy Exemption because it’s no longer necessary.³³ Notably, however, the CFTC explained that the alternative delivery procedures, such as netting, discussed in the 1993 Energy Exemption would continue to apply.³⁴ Regarding netting agreements that had been permitted by the 1993 Energy Exemption,³⁵ the CFTC explained the Edison Electric Institute Master Power Purchase and Sale Agreement, which contemplates a reduction to a net delivery amount of future, unintentionally offsetting delivery obligations, is consistent with the intent of the book-out provision in the Brent Interpretation. However, when entering into transactions, the parties must have a bona-fide intent to make or take delivery of the commodity covered by the agreement for the exclusion to apply.³⁶

Volumetric Optionality

Another major concern in the utility industry when Dodd-Frank was enacted was whether agreements that provided for some level of optionality would be considered swaps and regulated as such by the CFTC. As discussed, the commission generally exempted various types of energy contracts, with some levels of optionality, from the swap definition, provided the various conditions are met. In its swap definition interpretation the CFTC explained that a forward contract containing an embedded commodity option or options will be considered an excluded nonfinancial commodity forward contract (and not a swap) if the embedded option(s): i) may be used to adjust the forward contract price, without undermining the overall nature of the contract; ii) don’t target the delivery term, i.e., the predominant feature of the contract is actual delivery; and iii) can’t be severed and marketed separately from the contract.³⁷

In order to evaluate whether a transaction qualifies for the forward contract exclusions from the swap definition for nonfinancial commodities, the commission looks to the “specific facts and circumstances” to evaluate whether any optionality operates on the price or delivery term, and whether a commodity option is marketed or traded separately from the underlying contract.³⁸ The CFTC’s initial interpretation is that transactions with embedded volumetric optionality may satisfy the forward exclusions. Specifically, the CFTC stated that, if a transaction meets seven specific factors, then it would satisfy the forward exclusion.³⁹ Pertinent to utilities, the types of transactions that include optionality – but that would meet the forward exclusion to the swap definition, and hence generally not be regulated by the CFTC – include capacity contracts, transmission or transportation services agreements, tolling agreements, and peaking supply contracts.⁴⁰

RTO-ISO Exemption

Separate from the generic exclusions noted above, since the enactment of Dodd-Frank, the CFTC has exempted from broader regulation certain transactions that were historically and are currently regulated by FERC or by state commissions. Specifically, in an order effective April 2, 2013, issued in response to a petition by various regional transmission organizations (RTO) and independent system operators (ISO) (RTO-ISO Exemption Order),⁴¹ the CFTC exempted specific electric energy-related agreements, contracts, and transactions, as well as any person offering and entering into such transactions from all of the provisions of the CEA.⁴² The exempted transactions include those related to financial transmission rights, energy, forward capacity, and reserve or regulation transactions.⁴³ To be eligible for the exemption granted in the RTO-ISO Exemption Order the transaction must be offered or entered into in a market administered by a one of the RTOs or ISOs⁴⁴ covered by the Order pursuant to a said organization’s FERC-approved and effective tariff, rate schedule, or protocol. 

Notwithstanding the important RTO-ISO exemption, the CFTC’s anti-fraud and anti-manipulation authority, and scienter-based prohibitions continue to apply to RTO-ISO transactions. The RTO-ISO Exemption Order is expressly limited to market participants transacting in the requesting RTO-ISO markets that qualify as appropriate persons,⁴⁵ or eligible contract participants,⁴⁶ as those terms are defined in the CEA, e.g., financial institutions, banks, and investment companies, inter alia. Additionally, the RTO-ISO Exemption Order also applies to “persons who are in the business of: (i) generating, transmitting, or distributing electric energy, or (ii) providing electric energy services that are necessary to support the reliable operation of the transmission system.”⁴⁷

The RTO-ISO Exemption Order includes three conditions to the effectiveness of the included exemption. First, the requesting RTO-ISOs must demonstrate compliance⁴⁸ with FERC’s tariff creditworthiness provisions.⁴⁹ Second, the requesting RTO-ISOs must submit a legal memorandum⁵⁰ that provides assurance that the RTO-ISOs satisfy the standards set forth in FERC’s netting regulations⁵¹ and will provide the requesting RTO-ISOs with enforceable rights of set off against any of its market participants under the Bankruptcy Code, in the event of the bankruptcy of a market participant. The third condition concerns information sharing and the requesting RTO-ISOs must comply with the commission’s requests to share positional and transactional data.⁵²

Retail Transaction Exemption

In December 2011, the CFTC issued an interpretation⁵³ concerning its new jurisdiction over certain retail commodity transactions. The CFTC explained that the new jurisdiction broadly applied to any transaction in any commodity as if the transaction was a contract of sale of a commodity for future delivery.⁵⁴ The December 2011 interpretation also explained that it if actual delivery of the entire quantity of the commodity purchased occurred within 28 days, such transaction would be exempt from the retail commodity transactions definitions.⁵⁵ However, will the CFTC consider an agreement to supply electric or natural gas retail customers for a period of one year or more a “retail commodity transaction”? 

Late this summer, the CFTC clarified that sale and delivery of physical energy commodities to industrial, commercial, or retail customers on a recurring basis wouldn’t be considered retail commodity transactions as defined in the revised CEA⁵⁶ and, therefore, aren’t, inter alia, required to be conducted on a regulated exchange.⁵⁷ The potential risk to utilities and retail suppliers concerning what transactions would be deemed retail commodity transactions was that it was unclear whether retail residential gas and electric supply contracts met the narrow exemption provided in the Act.⁵⁸

Therefore, in August 2013 the CFTC issued a further interpretation explaining that the term “retail commodity transactions’’ as defined by the CEA wouldn’t encompass electricity or natural gas supply contracts intended to provide service to residential or business customers where the customer consumes the electricity or natural gas and subsequently pays for that usage, on a periodic basis.⁵⁹ The CFTC explained that it doesn’t interpret the new retail commodity transactions provisions as applying to such an electricity or natural gas supply contract, because the customer regularly receives delivery of and consumes energy commodity during the term of the contract and periodically pays for usage.⁶⁰

Dodd-Frank and End-Users

Dodd-Frank exposes end-users to potential regulatory requirements as a result of entering into certain types of transactions, such as being subject to the clearing requirements, under Dodd-Frank.⁶¹ This is of critical importance because the revised CEA provides that it shall be unlawful for any person to engage in a swap unless that person submits such swap for clearing to a derivatives clearing organization, if the swap is required to be cleared.⁶²

However, the CEA includes an end-user exception that provides that the aforementioned requirement doesn’t apply to a swap if one of the counterparties to the swap: “(i) is not a financial entity; (ii) is using swaps to hedge or mitigate commercial risk; and (iii) notifies the Commission, in a manner set forth by the Commission, how it generally meets its financial obligations associated with entering into non-cleared swaps.”⁶³ Additionally, if the end-user is a public company, Section 2(j) of the CEA⁶⁴ requires that for the exemptions to be applicable an appropriate committee of the issuer’s board or governing body is required to have reviewed and approved the decision to enter into swaps that are subject to end-user exception. In a Final Rule issued by the CFTC in July 2012,⁶⁵ the commission established rules that non-financial entities, such as energy companies, must follow if they choose to claim the end-user exemption. By satisfying the requirements end-users will be able to enter into swaps without having to comply with the mandatory clearing requirements. In addition to the requirements contained in the CEA for the exemption, quoted above, an end-user is required to satisfy certain reporting requirements. For example, an end-user may elect to make an annual filing that describes the counterparties to the transactions, explains whether the swaps are used to hedge or mitigate risk, how any financial obligations related to the uncleared swap will be satisfied. Therefore, as end-users, utilities may enter into swaps without the transactions being subject to the full panoply of the swaps regulations.

Dealer or Major Participant?

Another significant tile in the Dodd-Frank regulatory mosaic, and an important threshold question, is whether electric or natural gas utilities would be considered swap dealers or major swap participants under the CFTC regulations. As stated above, Dodd-Frank added a definition for the terms “swap dealer” and “major swap participant” to the CEA,⁶⁶ and the CFTC issued a Final Rule further clarifying the terms.⁶⁷ Generally, a swap dealer is a person that i) holds oneself out as a dealer in swaps, ii) makes a market in swaps, iii) regularly enters into swaps, or iv) engages in any activity causing that person to be commonly known in the trade as a dealer or market maker in swaps.⁶⁸

A major swap participant generally includes a person who isn’t a swap dealer, but i) maintains a substantial position in swaps; ii) whose outstanding swaps create substantial counterparty exposure; or iii) is a financial entity that is highly leveraged and maintains a substantial position in outstanding swaps.⁶⁹ Electric and natural gas utilities should be concerned about being labeled “swap dealers” or “major swap participants” because of the reporting, recordkeeping, margin, and business conduct rules that apply to these types of entities, thus increasing regulatory costs. 

Swap Dealers’ de Minimis Thresholds

Dodd-Frank requires that the CFTC “exempt from designation as a swap dealer an entity that engages in a de minimis quantity of swap dealing in connection with transactions with or on behalf of its customers.”⁷⁰ In clarifying its definition of swap dealer, the CFTC implemented various de minimis thresholds, below which entities would be excluded from the definition of swap dealer. In other words, an entity that engages in a de minimis level of swap dealing wouldn’t be considered a swap dealer and thus wouldn’t have to meet many of the capital, margin, and reporting and recordkeeping requirements.⁷¹ Therefore, if a utility engages in transactions that are considered swaps, as defined above, as long as the aggregate amount of the swaps are below the threshold, said utility won’t be subject to regulation as a swap dealer. The issue is that not all utilities have the same threshold values. 

The CFTC determined that a prudent approach would be to phase in the implementation of the de minimis thresholds. Moreover, as applicable to the energy industry, the CFTC implemented different de minimis thresholds for investor-owned utilities as compared to municipal utilities and other utilities considered special entities. Therefore, different thresholds apply for different types of utilities. 

Once the phase-in is complete, an entity won’t be considered a swap dealer if its swap dealing activity during the preceding 12 month period results in swap positions with an aggregate gross notional amount of no more than $3 billion.⁷² This de minimis threshold will be phased-in over time to facilitate orderly implementation of swap dealer requirements. During the phase-in period, the de minimis threshold will effectively be $8 billion.⁷³ The phase-in period will terminate five years after certain data starts to be reported to the swap data repositories, i.e., 2018, or the CFTC has the ability to revise the de minimis thresholds, prior to the expiration phase-in period.⁷⁴ Importantly, it isn’t entirely clear from the Swap Dealer Final Rule⁷⁵  how the lower threshold will be implemented once the phase-in period is concluded. The CFTC hasn’t explained how it will analyze the data collected during the phase-in period, or if it will provide regulated entities the ability to comment on the CFTC’s findings and whether the implementation of the lower threshold is appropriate. 

As noted above, the de minimis threshold is different for special entities. A “special entity” is a federal agency, state, state agency, city, county, municipality, other political subdivision of a state, employment benefit plan, government plan or endowment.⁷⁶ This definition would include a municipal utility or other public power agency. Initially the CFTC set the de minimis threshold for special entities at aggregate gross notional amount of no more than $25 million with no phase-in period for this threshold. The discrepancy between the $25 million special entity threshold and the initial $8 billion threshold creates a unique issue for the government owned electric and gas utilities. The intent behind the lower threshold for municipal energy companies is to protect these special entities from excessive losses, which the public ultimately would shoulder.⁷⁷ The reality is that, by implementing a $25 million threshold, the CFTC limited the number of market participants that were willing to deal with special entities.⁷⁸ Counterparties that would be below the initial $8 billion threshold might not be willing to trade with special entities out of concern for exceeding the special entity $25 million de minimis threshold, which could, in turn, trigger regulatory issues for the non-special entity counterparties.⁷⁹

In response to repeated requests from various special entities, the commission issued no-action relief allowing the de minimis threshold to be increased to $800 million for utility commodity swaps.⁸⁰ Specifically, the no-action relief stated that commission wouldn’t recommend the commencement of an enforcement action against a person for failure to apply to be registered as a swap dealer, if: i) the utility commodity swaps⁸¹ have an aggregate gross notional amount of no more than $800 million over a 12 month period; ii) the person isn’t otherwise a swap dealer; and iii) the person isn’t a financial entity, as defined in the CEA. Unfortunately, this no-action relief is limited to only those entities that provided the required notice to the CFTC. Specifically, to take advantage of the no-action relief and avoid the swap dealer registration, an entity was required to provide notice to the CFTC by Dec. 31, 2012.⁸² As such, if an entity that desired to be a counterparty in certain utility commodity swaps with municipal utilities or other public power agencies didn’t provide such notice, based on a strict reading of the relief granted, the special entity $25 million de minimis threshold, and not the higher $800 million threshold, applies. Therefore, if an entity desires to rely on the higher threshold, but didn’t provide the required notice, separate authorization from the CFTC is required. 

Dodd-Frank Mosaic

As the Dodd-Lincoln Letter indicates, the intent of Dodd-Frank wasn’t to regulate the activities of end-users, such as electric and natural gas utilities. The mosaic of rules and interpretations issued by the CFTC implementing the Act has generally provided a pathway for utilities to follow, whereby these types of end-users won’t be subject to every layer of Dodd-Frank’s comprehensive regulatory regime. In order to mitigate the regulatory burdens, a utility must be mindful to avoid transactions that would be considered swaps or aren’t covered by one of the many exemptions. Furthermore, if a utility enters into financial transactions that are swaps, the utility must be cognizant of the thresholds that, if crossed, would render such entities swap dealers or major swap participants.  

Endnotes:

1. See Dodd-Frank Act, Public Law 111–203, 124 Stat. 1376 (2010).

2. 7 U.S.C. § 1, et seq.

3. The regulatory burdens include, inter alia, new margin, clearing and reporting requirements for certain transactions.

4. See, e.g., the individual comments of Edison Electric Institute, American Gas Association, Electric Power Supply Association filed on Sept. 20, 2010 in response to the Advance Notice of Proposed Rulemaking and Request for Comments, Definitions Contained in Title VII of Dodd-Frank Wall Street Reform and Consumer Protection Act, 75 Fed. Reg. 51,429 (Aug. 20, 2010).

5. See Testimony of Chairman G. Gensler, before the U.S. Senate Committee on Agriculture, Nutrition & Forestry, (March 3, 2011) available at http://www.cftc.gov/PressRoom/SpeechesTestimony/opagensler-72.

6. See, e.g.,7 U.S.C. §§ 2, 6, 6b, 6c, 6o, 6s, 9, 9a, 12, 13, 13a-1, 13a-2, 13b and 13c.

7. See, n. 4, supra.

8. As discussed in detail below regarding the End-User Exception to the Clearing Requirement for Swaps, 77 Fed. Reg. 42560 (July 19, 2012) , the term “end-user” refers to a counterparties to a swap that “(i) is not a financial entity; (ii) is using swaps to hedge or mitigate commercial risk; and (iii) notifies the Commission, … , how it generally meets its financial obligations associated with entering into non-cleared swaps.” 7 U.S.C. § 2(h)(7)(A).

9. See the March 1, 2012 joint letter of Edison Electric Institute, American Gas Association, and the Electric Power Supply Association, supporting the Petition for Exemptive Relief for Certain Bona Fide Hedging Transactions Under Section 4a(a)(7) of the Commodity Exchange Act.

10. Exemption for Certain Contracts Involving Energy Products, 58 Fed. Reg. 21286 (April 20, 1993) (1993 Energy Exemption).

11. See, e.g., Interstate Commerce Act, 49 U.S.C. App. § 1, et seq.; Natural Gas Act 15 U.S.C. 717, et seq.; Federal Power Act, 16 U.S.C. 791a, et seq.

12. See 1993 Energy Exemption. As previously discussed, even if a transaction is exempt from certain requirements, the CFTC’s general anti-fraud and anti-manipulation authority, and scienter-based prohibitions under CEA continue to apply. Notably, Section 720 of Dodd-Frank requires that the CFTC and FERC negotiate a memorandum of understanding to establish procedures for applying their respective authorities; resolving conflicts concerning overlapping jurisdiction; and avoiding conflicting or duplicative regulation. The CFTC and FERC have yet to enter into such a memorandum of understanding. Therefore, the exact jurisdiction of the two agencies concerning energy related transactions is still an open question. InHunter v. FERC, 711 F.3d 155 (D.C. Cir. 2013), however, the court held that the CFTC has exclusive jurisdiction over futures contracts and, therefore, FERC lacked jurisdiction to charge a market participant with manipulation of natural gas futures contracts.

13. See“Financial reform bill wins final approval in Senate, now awaits president’s signature,” Inside FERC, (July 19, 2010) (discussing how the energy industry had concerns that end-users would be caught up in a requirement to clear trades and be subject to stricter requirements).

14. See“Energy industry groups urge CFTC to limit reform’s impact, reach deal with FERC,” Inside FERC, (June 13, 2011).

15. Letter from Senator C. Dodd and Senator B. Lincoln to Rep. B. Frank and Rep. C. Peterson (Dated June 30, 2010) (Dodd-Lincoln Letter).

16. Dodd-Frank, § 721.

17. 7 U.S.C. § 1a(47). A swap includes, inter alia, any transaction that is a “put, call, cap, floor, collar, or similar option of any kind that is for the purchase or sale, or based on the value, of 1 or more interest or other rates, currencies, commodities, securities, instruments of indebtedness, indices, quantitative measures, or other financial or economic interests or property of any kind” or “that provides for any purchase, sale, payment, or delivery (other than a dividend on an equity security) that is dependent on the occurrence, nonoccurrence, or the extent of the occurrence of an event or contingency associated with a potential financial, economic, or commercial consequence.” However a swap isn’t “any sale of a nonfinancial commodity or security for deferred shipment or delivery, so long as the transaction is intended to be physically settled.” 7 U.S.C. § 1a(47)(B)(ii).

18. 7 U.S.C. § 1a(49). A swap dealer includes any swap person that “holds itself out as a dealer in swaps;” “makes a market in swaps;” “regularly enters into swaps with counterparties as an ordinary course of business for its own account;” or “engages in any activity causing the person to be commonly known in the trade as a dealer or market maker in swaps.”

19. 7 U.S.C. § 1a(33). A major swap participant includes any person who isn’t a swap dealer, and “maintains a substantial position in swaps for any of the major swap categories;” “whose outstanding swaps create substantial counterparty exposure that could have serious adverse effects on the financial stability of the United States banking system or financial markets;” or “is a financial entity that is highly leveraged relative to the amount of capital it holds and that is not subject to capital requirements established by an appropriate Federal banking agency;” and “maintains a substantial position in outstanding swaps in any major swap category as determined by the Commission.”

20. Dodd-Frank, §712(d)(1).

21. See 7 U.S.C. §1a(47)(A).

22. 7 U.S.C. § 1a(47)(B)(ii).

23. Further Definition of “Swap,” “Security-Based Swap,” and “Security-Based Swap Agreement;” Mixed Swaps; Security-Based Swap Agreement Recordkeeping, 77 Fed. Reg. 48208 (Aug. 13, 2012) (Swap Definition Rule).

24. Swap Definition Rule at 48232.

25. Id. at 48233.

26. Id. at 48229.

27. Id. at 48227.

28. Id. at 48227, 48228

29. Id. at 48239.

30. Statutory Interpretation Concerning Forward Transactions, 55 Fed. Reg. 39188 (Sept. 25, 1990) (Brent Interpretation).

31. Swap Definition Rule at 48228.

32. Brent Interpretation at 39192.

33. Swap Definition Rule at 48229-48230; see, n. 10, supra.

34. Id.

35. 1993 Energy Exemption at 21293.

36. Swap Definition Rule at 48230.

37. Id. at 48237.

38. Id.

39. Id. at 48238. The seven part test is: (1) The optionality does not undermine the overall nature of the transaction as a forward contract; (2) The predominant feature of the transaction is actual delivery; (3) The optionality cannot be severed from the overall transaction; (4) The seller of a nonfinancial commodity underlying the transaction intends, at the time it enters into the transaction to deliver the underlying nonfinancial commodity if the optionality is exercised; (5) The buyer of a nonfinancial commodity underlying the transaction intends, at the time it enters into the transaction, to take delivery of the underlying nonfinancial commodity if it exercises the embedded volumetric optionality; (6) Both parties are commercial parties; and (7) The exercise or non-exercise of the embedded volumetric optionality is based primarily on physical factors, or regulatory requirements, that are outside the control of the parties and are influencing demand for, or supply of, the nonfinancial commodity.

40. Id. at 48240.

41. Final Order in Response to a Petition From Certain Independent System Operators and Regional Transmission Organizations To Exempt Specified Transactions Authorized by a Tariff or Protocol Approved by the Federal Energy Regulatory Commission or the Public Utility Commission of Texas From Certain Provisions of the Commodity Exchange Act Pursuant to the Authority Provided in the Act, RIN 3038–AE02, 78 Fed. Reg. 19880 (April 2, 2013).

42. The RTO-ISO Exemption Order didn’t grant an exemption to the Commission’s general anti-fraud and anti-manipulation authority. RTO-ISO Exemption Order at 19912.

43. RTO-ISO Exemption Order at 19882-19883.

44. The RTOs and ISOs include: Midwest Independent Transmission System Operator.; ISO New England.; PJM Interconnection, California Independent System Operator and New York Independent System Operator. The RTO-ISO Exemption Order also applies to the Electric Reliability Council of Texas.

45. 7 U.S.C. §§ 6(c)(3)(A)–(J).

46. 7 U.S.C. § 1a(18).

47. RTO-ISO Exemption Order at 19912.

48. Id. at 19889.

49. 18 C.F.R. § 35.47 (2013).

50. RTO-ISO Exemption Order at 19890.

51. 18 C.F.R § 35.47(d).

52. RTO-ISO Exemption Order at 19892.

53. Retail Commodity Transactions Under Commodity Exchange Act, 76 Fed. Reg. 77670 (Dec. 14, 2011).

54. Id. at 77671.

55. Id. at 77672; see 7 U.S.C.§ 2(c)(2)(D)(ii)(III)(aa).

56. 7 U.S.C.§ 2(c)(2)(D).

57. Retail Commodity Transactions Under Commodity Exchange Act, 78 Fed. Reg. 52426 (Aug. 28, 2013) (August 2013 Retail Commodity Transactions Interpretation).

58. See Comments of Constellation Energy Group, et al., filed on Feb. 13, 2013 on the Interpretation Regarding Retail Commodity Transactions Under the Exchange Act.

59. August 2013 Retail Commodity Transactions Interpretation at 52426.

60. Id. at 52428.

61. 7 U.S.C. § 2(h).

62. Id.

63. 7 U.S.C. § 2(h)(7); End-User Exception to the Clearing Requirement for Swaps, 77 Fed. Reg. 42560 (July 19, 2012).

64. 7 U.S.C. § 2(j).

65. End-User Exception to the Clearing Requirement for Swaps, n. 63, supra.

66. 7 U.S.C. § 1a(33) and (49).

67. Further Definition of ‘‘Swap Dealer,’’ ‘‘Security-Based Swap Dealer,’’ ‘‘Major Swap Participant,’’ ‘‘Major Security-Based Swap Participant’’ and ‘‘Eligible Contract Participant,’’ 77 Fed. Reg. 30596 (May 23, 2012) (Swap Dealer Final Rule).

68. 7 U.S.C. § 1a(49)(A).

69. 7 U.S.C. § 1a(33).

70. 7 U.S.C. § 1a(49)(D).

71. Swap Dealer Final Rule at 30597.

72. Id.  at 30726; see also 17 C.F.R §1.3(ggg)(4).

73. Id. at 30634.

74. Id. at 30641.

75. See n. 67, supra.

76. 7 U.S.C. § 6s(h)(2)(c).

77. Swap Dealer Final Rule at 30628, n. 410.

78. Testimony of the Commissioner Scott D. O’Malia Before the Subcommittee on General Farm Commodities and Risk Management House Committee on Agriculture (July 23, 2013): “While this rule was written with the best of intentions, by reducing the de minimis threshold to $25 million, the end result has been a reduction in the number of market participants that are willing to do business with Special Entities.” 

79. Id.:“Many counterparties that would fall well below the $8 billion de minimis threshold are not willing to trade with Special Entities for fear of exceeding the $25 million cap and then having to register with the Commission as swap dealers.”

80. Staff No-Action Relief: Temporary Relief from the De Minimis Threshold for Certain Swaps with Special Entities, CFTC Letter No. 12-18 (Oct. 12, 2012) (CFTC Letter No. 12-18).

81. For purposes of the no-action relief, the term “utility commodity swap” means any swap that meets all of the following conditions: a) a party to the swap is a utility special entity; b) a party to the swap that is a utility special entity is using the swap in the manner described in 17 C.F.R. § 1.3(ggg)(6)(iii); and c) the swap is related to an exempt commodity in which both parties to the swap transact as part of the normal course of their physical energy businesses.

82. CFTC Letter No. 12-18 at 5.

Back in late September, the Federal Energy Regulatory Commission gathered some two dozen experts to explain to FERC what capacity markets ought to look like, and if needed, to recommend new policies.

The group arrived with lofty credentials, prompting junior Commissioner Tony Clark to salute all the “regulatory geeks” that had come to Washington:

“It’s not often we get together in the same room to pick the brains of some of the smartest minds in the country.”

But his colleague, Cheryl LaFleur – and recently tabbed as the new interim FERC chairman by outgoing head Jon Wellinghoff – wondered what exactly had been learned after a full day of discussion:

“About the only thing your testimonies have in common,” she observed, “is maybe that none of the markets are getting the prices right … Does anyone have any suggestions as to what we should do?

 “Or we can go back to being like the blind man and the elephant, only eight hours smarter.”

Yet perhaps LaFleur struck the wrong metaphor. Forget the pachyderm. Rather, think of capacity markets as looking less like an elephant, and more like a duck.

Or “duck curve,” to be more specific.

According to Phil Pettingill, director of state regulatory strategy for the California ISO, who spoke with Fortnightly in November, the duck curve first emerged as a policy driver at least as early as this past February, when Cal-ISO and the California Public Utilities Commission (CPUC) had convened a “summit” on long-term resource adequacy. But it really caught fire in July, he explained. That’s when FERC held a technical conference in Sacramento to discuss what to do after it had rejected¹ the CAL-ISO’s FLRR plan (flexible capacity and local reliability resource retention), which would’ve imposed what some called a “tax” on power customers to ensure resource adequacy against the risk of plant retirements.

In simple terms, the “duck” shows how the large influx of variable and intermittent renewable resources expected in California in the next few years will put a premium on ramping – the ability of traditional, dispatchable generators to increase or reduce output at various predictable times of day to offset spikes or troughs in solar and wind output. And if fossil generation can’t ramp fast enough, it might prove necessary, as some have warned, to curtail wind or even solar early in the day, in favor of gas, so that traditional, dispatchable resources are on-line and firing when renewable energy output falls as afternoon turns to evening. (See Figure 1.)

Word of the duck quickly made its way back East. The concept figured prominently in FERC’s September conference on capacity markets, in large part due to a study the FERC staff had released a few weeks earlier, in late August.

The FERC staff study presented a primer on capacity markets, from A to Z. It had outlined current market designs in PJM, ISO New England, and the New York ISO, along with some key ideas for reform, in especially in terms of how to define the capacity product that’s bought and sold in those regional markets.²

But the staff report also noted that power system operators were beginning to think about defining the capacity product “more granularly,” to better reflect real-world needs: e.g., quick-start and fast-ramping capability; regulation and load-following capability; fuel risk, such as from heavy reliance on gas-fired generation; resource diversity needs (too much demand response?); and even political mandates, such as renewable portfolio standards, or a certain array of resources favored under state-approved integrated resource plans.

Thus, the staff report helped prompt a fierce debate at the September conference on whether regional capacity markets at the eastern ISOs ought to include separate bid tranches for some of these resource categories.

Commissioner LaFleur launched the debate in earnest after the lunch break, at the 4½ hour mark:

“The concept of promoting a specific resource is in direct tension with the concept of a technology neutral capacity market. What about having separate tranches, like a base-load tranche, a green tranche, a ramping tranche? We get comments on that.”

Untenable Complexity

Closer to the start of the conference, David Patton of Potomac Economics (which serves as independent market monitor for ISO New England and the New York ISO) proposed that capacity markets must include three elements: 1) locational pricing, 2) a downward-sloping demand curve, and 3) supply- and buyer-side mitigation to guard against exercise of market power. This third element typically results in a mandatory ceiling and floor for bids submitted by players that fail to qualify for an exemption from bid mitigation.

Patton mentioned a multi-year forward commitment as “important,” but not essential. This last distinction was noteworthy, as New England’s Forward Capacity Market stands alone as still maintaining a vertical, rather than sloping demand curve, while the New York’s ICAP remains the only Eastern capacity market that doesn’t look forward in years, as it commits resources only six months ahead.

No one at the conference much questioned locational pricing. But Patton’s other points drew comment.

For example, when asked point blank by FERC Commissioner Clark about progress in stakeholder discussions, Robert Ethier, ISO-NE’s v.p. of market development, assured Clark that “we expect sometime next year to approach FERC and propose a sloped demand curve.”

Regarding a multi-year forward commitment, Rana Mukerji, the NY ISO’s senior v.p. for market structures noted, “We’ve considered going to a forward market [but] decided against that because [it] tends to over-procure.”

And that was the same conclusion that Scott Harvey, William Hogan, and Susan Pope had drawn in March of this year, in a study they prepared to offer policy recommendations to the New York ISO:

“[T]he planning process used to determine capacity targets under such a forward procurement process [similar to PJM’s three-year forward commitment] would have the potential to systematically increase the amount of capacity procured relative to the current capacity market design, thereby increasing the cost of power out of proportion to the increase in reliability.³

But on the question of buyer-side mitigation, Murkerji conceded that New York’s policy had proven problematic over the years – “much more difficult … has sparked a lot of controversy.” He suggested that New York perhaps could think about eliminating buyer-side mitigation in the case of merchant generation plants that have no rate base support.

Seconding that motion, albeit from the PJM footprint, was Ed Tatum, v.p. for RTO and regulatory affairs at Old Dominion Electric Co-op:

“Stop looking behind every tree for buyer-side monopsony power.”

But on the key question – tranches in RTO capacity markets – the overwhelming sentiment was “no.”

James Wilson, of Wilson Energy Economics: “Count me among the purists who feel that capacity markets should focus on peak scarcity … rather than branch out into tranches.”

Peter Crampton, professor of economics, University of Maryland: “the idea of tranches in capacity markets is a nightmare. Now you will need a demand curve for each tranche.”

Sue Kelly, general counsel and sr. v.p., policy analysis, American Public Power Association: “There is a diversity of opinion within my own membership. There is interest in tranches in some regions… [but] … I am personally worried about arbitraging between these markets. And tranches just means more markets for arbitrage.”

Robert Ethier, ISO-NE: “Is the purpose to price discriminate, so that one resource gets paid more than another? My belief is that tranches are not necessary to get all of the resource attributes that you need. A year and a half ago [we] considered this idea, but moved on.”

Also, as shown by past rulings, the commission has insisted on a MOPR (minimum offer price rule) to ensure that state-sponsored resources or OOM (out-of-market) generators can’t use rate base support or other guaranteed revenue streams to subsidize below-market supply offers that might depress prices artificially in regional capacity markets.

Yet if FERC should mandate bidding tranches in capacity markets, in essence creating a carve-out for certain resource categories, might that also push prices down, creating the same unwanted effect of a subsidized, state-sponsored project?

Commissioner LaFleur admitted as such:

“What about the idea that renewables are … granted a MOPR exemption? Even though intent is good – no intent to manipulate pricing – don’t these resources have the same price-lowering effect as a different state-sponsored resource introduced into the market specifically to lower the capacity prices?”

“Yes, you’re right,” answered Robert Erwin, general counsel for the Maryland Public Service Commission which, along with New Jersey, has attempted in the past to sponsor out-of-market resources to help force down capacity prices.

“But that’s no different,” he added, “ than when a state imposes an environmental rule that forces a dirty plant to close and therefore has the effect of raising the clearing price, because a more expensive plant takes its place.”

Even the former FERC Commissioner William Massey, speaking for the COMPETE Coalition, a staunch advocate of competitive power markets, was inclined to concede the point:

“The effect is the same, in theory.”

Instead of tranches, the experts said the industry would be better off relying on spot energy markets, which, they explained, are more attuned to the physical, locational, and temporal needs of resource adequacy.

But are energy prices high enough? Many felt not, challenging FERC and the ISOs to concentrate on scarcity pricing rules. Even Michael Hogan, representing the Regulatory Assistance Project, admitted that if you get scarcity pricing right in the energy market, “the argument for capacity markets gets pretty thin.”

Yet FERC commissioner John Norris hit the nail on the head:

“We know there is political opposition to letting prices rise in the energy market. So which is it: political problems or untenable complexity?”

Most experts favored the first option – to get prices “right.” Prompting a this answer from Sue Kelly:

“Get the prices right? This worries me.

“It’s like Paul Newman, in prison [in Cool Hand Luke, the 1960s-era film] and being told he has to ‘get his mind right.’

“It makes me all the more desirous of having a physical hedge against those prices by contracting forward.”

But Ethier, from ISO-NE, whose panel had finished its work in the morning session, now rose from far back in the meeting room, where he was sitting in the audience, and grabbed a microphone so that he could join the discussion and put in his plug for solving the problem through spot energy and reserves markets.

“It’s a false choice,” he argued, “to say, ‘do we need to do it spot, or do it forward.”

Even if you have some way, as he explained, to ensure resource flexibility in the capacity market, then you still need a robust spot market, he said, “to cash out your position.”

Said Ethier: “At a minimum, we need to do it spot. The question, then, is do we need to do it also forward.”

New York to California

And yet the September conference doesn’t tell the whole story.

In November, it seemed, nearly all the nation’s regional grids were involved in some way or another in fierce debates over capacity markets.

In New York, the ISO was still working through the details of a recent FERC order that authorized formation of a new ICAP market zone – with all the implications that could have for the traditionally high-priced New York in-city zone.

And in California, the ISO and the CPUC were agreeing (perhaps for the first time ever) to work together toward adopting a market-based backstop for resource adequacy.

At the New York ISO, in August, the ISO won FERC approval to set up a geographic zone for its ICAP market, covering the ISO load zones G, H, and I in the lower Hudson Valley (see Figure 2), but also including the New York City load zone J as a “nested” zone within LHV.⁴

But this move has drawn ire from the New York PSC, which fears that the move will simply cause the traditionally high ICAP prices in New York’s In-City Zone J to be exported to lower Hudson ratepayers (heretofore listed in the low-cost “rest of state” ICAP zone) to subsidize New York’s high in-city ICAP prices. In a rehearing request, the PSC claimed that without some sort of phase-in to soften the blow, retail consumer rates in the lower Hudson could climb as much as 25 percent on implementation of the new zone.⁵ Central Hudson Gas & Electric wrote of “rapidly approaching rate shock,” warning of wholesale capacity increases as much as 475 percent.⁶

Also, the PSC has asked FERC to instruct the ISO to develop a new tariff that would create a process for disassembling the new zone. The PSC claims that good cause might arise later for unmaking the zone if Gov. Andrew Cuomo’s “Energy Highway Blueprint” comes to fruition, resulting in construction of new transmission facilities that could remove the North-South constraints that led the ISO to create the zone in the first place.

According to NYISO’s Mukerji who spoke with Fortnightly on November 25, the PSC’s complaints didn’t come out of the blue. The ISO had been well aware of possible effects on retail rates, but thought it better “to remain silent” on that until the PSC could quantify the numbers. And so, in late October, after the numbers had come in, the ISO moved quickly to soften any untoward rate effects by proposing phase-in of price effects on the G-J zonal locality, describing it as “necessary to ameliorate effects on consumers.”⁷

As Mukerji adds, transmission constraints leading from upstate to South of Albany have been known for quite some time: “The LHV Zone should’ve been created six or seven years ago,” he says.

Now that the new zone has been formed, however, he acknowledges that the ISO plans to take another look, convening talks with stakeholders next year to explore ideas, including the notion of a possible tariff rule to govern the unmaking of zones.

Of course, much could depend upon the progress of the governor’s EHB grid initiative. As an ISO spokesman also told Fortnightly,“we remain fully supportive of the governor’s energy highway proposal.”

Meanwhile, just before Thanksgiving, as this issue was going to press, the FERC announced its ruling in Hudson Trans. Partners v. NY ISO,⁸ the case that Ed Krapels and William Hollaway write about in this issue in their feature article, “Category Error” (p.44). As reported by the commission staff, the FERC order affirms the ISO’s underlying decision to apply buyer-side market mitigation (a sort of bid floor) to HTP’s new merchant transmission facility, but grants the complaint to the extent that it requires the ISO to provide a more complete and detailed explanation of the mathematical factors built into the mitigation process.

On the other coast, on November 8, the California PUC announced a “joint reliability plan,” executed with the Cal-ISO, whereby two agencies would cooperate on efforts to work toward advancing three separate initiatives: 1) to extend the CPUC’s resource adequacy program, to possibly create a two- to three-year forward procurement obligation; 2) to conduct a joint CPUC-ISO resource adequacy planning assessment up to 10 years forward; and 3) to launch a stakeholder process to explore development of a “reliability services auction” – a market-based backstop at the ISO for capacity procurement. As Pettingill told Fortnightly, the RSA would resemble to some extent the residual capacity auction adopted by the Midcontinent ISO to back up bilateral capacity procurement, but that California’s RSA, contrary to the MISO program, wouldn’t be voluntary.

And this new move from California shows how the Cal-ISO wants to avoid the conflicts seen Back East, where states, such as Maryland and New Jersey have battled PJM for primacy in resource planning, also as documented this issue in the article, “Partnership, Not Preemption,” by Messrs. Roach, Mossburg, and Musco (p.34).

Pettingill adds that the joint PUC-ISO effort to develop a market-based yet residual capacity auction was very much informed by such conflicts:

“In various ways,” he notes, “FERC has communicated to us that we need to come up with a proposal that the PUC could support.”

No Excuses

In New England, at a meeting on November 15, the NEPOOL Markets Committee voted against a comprehensive proposal by ISO management to adopt a new performance incentive structure for the region’s Forward Capacity Market (FCM). As proposed, the new regime would both reward and penalize resource owners, if they should exceed or fall short of their capacity supply obligations, as measured by way of comparison of the performance of their peers. ISO management has long pushed for such reform, especially as a way to counter the risk of the region’s over-dependence on gas-fired generation.

The ISO’s failure to get the proposal past appears to stem from two factors: a) worries about the cost of the program; and b) insistence from power producers that they deserve some sort of exemption or waiver from the performance standard if their failure to perform comes because ISO actions limited their output.

Of course, it’s widely known that last winter the New England region found itself engaged in a dangerous dance with a reliability collapse. As we noted in April’s Commission Watch column,⁹ (“No Fuel, No Power”), ISO New England reported in February that of the 36 largest electric system contingency events recorded over the three prior years, the response rate for the region’s non-hydro resources that were dispatched to meet those contingencies (largely fast-starting resources and spinning reserves) totaled less than 60 percent of what the ISO had requested.

But now we learn that the problem extends into the summer peak as well.

In his written statement at the FERC’s September conference on capacity markets, Ethier explained how ISO New England had found itself in much the same sort of trouble this past summer during a heat wave that stretched from Monday, July 15, to Friday, July 19 – a time when the region’s gas-fired generators obviously wouldn’t face competition from winter space-heating load.

As Ethier explained, on that Friday the regional system was short of reserves for roughly five hours despite having excess capacity as measured nominally by “steel in the ground.” That’s because, as Ethier reports, when the ISO had sent out start orders to generators, nearly 15 percent of resources having capacity supply obligations proved to be unavailable.

“At the peak hour,” he writes, the deficiency was 547 MW, nearly 25 percent of the reserve requirement of 2,374 MW.

Back in July, Robert Stoddard of Charles River Associates had raised alarms that the ISO’s new performance incentive plan could lead to annual cost increases for the region’s FCM “likely to range between $1 billion and $4 billion,” owing in part to the higher risk of taking on a capacity supply obligation.¹⁰

But those warnings were countered by a later study from the Analysis Group finding that annual FCM costs – and that’s total costs, not an increment of increase – would range only from $1.56 billion to $1.86 billion, depending upon the particular scenario, if any, governing natural gas shortage. According to the study, such totals would represent increases in total FCM costs ranging from 25 percent to 49 percent, across the various gas supply scenarios.¹¹

According to Ethier, the ISO wants the FCM performance incentive plan to work like an energy-only market, with no excuses:

“It does not matter why you did not perform when needed – if you perform you get paid, otherwise you get nothing.”

In late November, a spokesperson from ISO-NE told Fortnightly that the ISO would present its proposal again, this time to the NEPOOL Participants Committee, for a vote at a meeting to be held December 6.

Unsustainable

On November 21, the PJM Markets and Reliability Committee approved a tariff proposal titled, “Demand Response as an Operational Capacity Resource” – a move that will require DR suppliers to incorporate an energy strike price in their supply bids offered in the region’s capacity market, known as the RPM (Reliability Pricing Model). Under this new tariff, PJM grid operators may call on so-called “limited” DR as soon as constraints start to bind, and prices begin to climb, without having to wait for a reserves emergency to be declared – thus integrating DR into the resource mix with full diversity, instead of as an all-or-nothing block that leaves operators without fully flexible options.

This initiative was one of four proposed changes to RPM announced by Andy Ott, PJM’s executive v.p. of markets, in a media briefing on November 15. The other reforms would address capacity imports, anomalous RPM price relationships between certain DR categories, and questionable bidding behavior, suggesting that some capacity supply offers might be purely speculative. That belief stems from analysis by PJM that resource owners, having first cleared in the RPM in the three-year forward base residual auction, are then later attempting to buy out their capacity supply obligations in the incremental auctions, which are staged closer to the delivery year.

A spokesman from PJM who talked with Fortnightly on November 22 said the DR operational proposal will now move to the full members committee where, if endorsed, it will then proceed to the PJM board for approval and a possible tariff filing at FERC. Meanwhile, the spokesman added, the bidding behavior issue, known in PJM parlance as the “replacement capacity” issue, and which was scheduled initially to be presented to the members committee for endorsement on December 13, will instead be returned to the capacity senior task force, which will attempt to forge more precise tariff language.

Importantly, PJM’s Ott took time at the September FERC conference to emphasize the importance of the DR operational initiative, explaining how, at present, without the needed reform, the DR resources cleared in the PJM RPM are dragging down the diversity of the region’s resource mix:

“To some extent,” as Ott testified in September, “we are victims of our own success.

“We have 14,000 MW of demand response … [clearing in RPM] … but 13,000 of it gives us only two hours’ notice and the same price. So I have an 8 to 9 percent resource block that all looks the same.

“We can’t sustain that.”

Endnotes:

1. Dkt. ER13-550, Mar. 29, 2013, 142 FERC ¶61,248.

2. Centralized Capacity Market Design Elements, FERC Dkt. AD13-7, Aug. 23, 2013.

3. Evaluation of the New York Capacity Market, FTI Consulting, March 2013, exec. summary, p. xii.

4. Dkt. ER1380, Aug. 13, 2013, 144 FERC ¶61,126.

5. Request for Rehearing, pp. 5, 9-10, FERC Dkt. ER13-1380-001, Sept. 12, 2013.

6. Request for Rehearing, pp. 2, 8-9, 15, FERC dkt. ER13-1380-002, filed Sept. 12, 2013.

7. Request for Partial Reconsideration, FERC Kt. ER13-1380-000, filed Oct. 28, 2013.

8. Dkt. EL12-98, Nov. 21, 2013, 145 FERC ¶61,156.

9. “No Fuel, No Power,” Public Utilities Fortnightly, April 2013, p. 20.

10. Performance Incentives in ISO New England’s Forward Capacity Market, pp. 11-12, study prepared for NextEra Energy Resources, CRA Project D18053-01, July 2, 2013.

11. Assessment of the Impact of ISO-NE’s Proposed Forward Capacity Market Performance Incentives, by Todd Schatzki and Paul Hibbard, The Analysis Group, September 2013, p. 4.

Two cases decided recently in federal court have reignited the long-standing debate over the jurisdictional boundary between federal and state regulation of the electricity business.¹ The plaintiffs in both cases argued that because the Federal Energy Regulatory Commission (FERC) had created a capacity market within the PJM regional transmission organization, the states were preempted from playing their traditional role in resource planning. In a companion argument, they claimed such state action would unduly restrict interstate commerce.

The judges in the two U.S. District Courts in Maryland and New Jersey – the two states that were defendants – each ruled in favor of the plaintiffs on the preemption issue. They declared that the efforts of the two states to procure new generation to serve their ratepayers violated the Supremacy Clause of the U.S. Constitution. Our purpose in this article isn’t to analyze or to critique the judges’ decisions; each was thorough and well explained from a legal standpoint. Nor do we speculate on the future of the new generation projects procured by these two state programs. Instead, our purpose is to explain the potential negative policy implications of these rulings going forward.

Preempting the states is a bad idea. Let’s consider four reasons, founded in public policy and economics.

First, only the states have authority under the Federal Power Act to order the construction of new generation capacity to mitigate long-term risks. Such risks include delays in building major transmission facilities, sudden and substantial retirements of existing power plants (often in the face of new environmental regulations), abrupt changes in load (especially as we come out of the Great Recession), the need to accommodate intermittent generation by solar and wind facilities, and the failure of the PJM capacity market to attract a diversified portfolio of resources in transmission-constrained areas. It would be dangerous to take that authority away from the states in the face of these significant risks.

Second, if the logic of the plaintiffs’ arguments is carried forward it could wipe away a broad swath of state programs. The logic is that states are preempted when their programs “affect” or alternatively “set” prices in wholesale markets. The latter argument was what both judges accepted in ruling that the Supremacy Clause had been violated.² Yet since almost any state program will affect supply or demand, all could be said to “affect” wholesale prices. Moreover, the policy structures of the Maryland and New Jersey programs that were challenged by the plaintiffs were no different from many other widely accepted state programs that also happen to “set” prices. The policy structure is first to say that the state wants more of a certain kind of resource, then to offer a price guarantee to ensure that resource gets built, and to insulate the builder from the volatility of short-term prices in FERC-approved markets.

Third, the short-term products solicited in the FERC-approved capacity market are fundamentally different from the long-term products solicited through state-run competitive procurements. The PJM capacity market asks for a one-year commitment only, while Maryland and New Jersey were asking for 15 years or more. Plus, the states were requiring that bidders build new generation facilities and that their prices be fixed (in part) for that 15-(plus)-year term. Different products mean different markets, but the two can coexist. Short-term and long-term markets coexist in many businesses despite the fact that one market may affect the price in the other market; the short-term housing rental and long-term housing sale markets offer a good analogy, as do short and long-term bond markets. 

Fourth, states are responding appropriately to FERC’s market design. If interstate commerce is influenced in any way, it’s the result of the locational pricing required by FERC, not the alleged parochial interests of the states. In FERC’s capacity market, when transmission constraints or other constraints are binding, the capacity market is balkanized, meaning that different locations have different prices. FERC intended that new generation be built in higher-priced locations – that’s exactly what the states in these cases were doing. To do otherwise would put ratepayers at risk, paying for capacity for which they get no benefit because FERC rules could make it undeliverable. (Neither judge found that the state had violated the Commerce Clause.)³

The bottom line is that a federal-state partnership is the right policy, not federal preemption, as was argued by the plaintiffs in these two cases. Render unto FERC what is FERC’s: the short-term capacity market. And render unto states what is theirs: a long-term capacity procurement tied to resource planning. Short-term and long-term markets can and do coexist and benefit one another. As to potential harm, FERC should remain free to protect its market from uneconomic entry, as it has done already. Moreover, by leaving long-term resource planning to the states, America gets the diversified portfolio of resources it needs. That diversity happens naturally because the states differ in their assessments of the uncertainties the nation faces and in their resource preferences.

But with these two decisions standing in the way, we risk endangering our claim to a truly diversified portfolio of resources.

The Programs and their Aims

The cases in question both centered on states taking action to ensure construction of new generating capacity.

The first case comes from New Jersey, where, in early 2011, out of concern for the lack of new generation in the region, the state legislature created the Long-term Capacity Agreement Pilot Program or LCAPP.⁴ This program offered long-term (up to 15 years) capacity price guarantees to developers who would build new base-load or mid-merit generating plants. The price guarantee would be used to attract financing for the project and, in return, the developer would construct and operate its plant, selling all of its capacity and energy into the PJM wholesale markets for the duration of the guarantee. 

The guarantee took the form of a swap on the price of capacity as set by PJM’s annual capacity auction called the Reliability Pricing Model or RPM. New Jersey ratepayers would guarantee a fixed capacity price to the developer, and, in return, would receive the RPM capacity revenue. These amounts were netted against each other, so the actual money that changed hands would simply equal the difference between the two prices. If the RPM price was higher than the guaranteed fixed price, ratepayers would receivethe difference from the developer. If it was lower, they’d pay the difference to the developer. To implement the LCAPP, the New Jersey Board of Public Utilities (BPU) held a competitive procurement in which developers were invited to submit proposals, including a required fixed price for their capacity. The BPU then invited the three lowest-cost bids to sign 15-year swap agreements, each representing a new natural-gas-fired combined cycle facility amounting to about 1,948 MW of new capacity in total.⁵

The second case began in Maryland, where, in late 2011, the Maryland Public Service Commission (PSC), with concerns similar to those in New Jersey, had issued a “Request for Proposals for Generation Capacity Resources Under Long-Term Contract” (the Long-Term RFP).⁶ This RFP was open only to new natural gas-fired plants willing to locate in PJM’s Southwest MAAC Locational Deliverability Area (LDA), which includes the service territories of Baltimore Gas & Electric and Pepco. Developers had to construct a new plant and sell into the PJM capacity and energy markets. In return they’d receive a long-term (15-year or more) price guarantee. The price guarantee was slightly different from that offered in New Jersey. In the Maryland RFP, developers proposed a price equal to the total revenue requirement needed per year to build the plant, from which would be subtracted capacity market revenues and profits made from the sale of energy. Again, the actual payments made to or by ratepayers would be the difference between the developer’s guaranteed price and the market revenues received. The PSC issued the RFP and received competing proposals, and ultimately selected the single, lowest-cost proposal to sign to a 20-year agreement for a 661 MW natural gas-fired combined cycle plant.⁷

Plaintiffs’ Claims

The plaintiffs in the New Jersey and Maryland cases included a group of parties, consisting of owners of existing generation and electric distribution companies, who brought claims in a number of different venues. Here, however, we focus only on the two suits in U.S. District Court.⁸

The plaintiffs claimed that the new supply created by these programs would cause them harm by lowering the prices they receive for capacity and energy from PJM markets. This claim was founded on two primary arguments, each centered on the issue of federal preemption.

First, they argued that the state-sponsored programs were unlawful under the Supremacy Clause because the FERC has “occupied the field” of wholesale energy and capacity sales by creating markets for both, and that, given these FERC markets, states are preempted. The plaintiffs said the Maryland and New Jersey programs were unlawful specifically because they’d “affect” the price of wholesale capacity and energy in FERC markets.⁹ The plaintiffs further refined this claim to contend that the programs actually “set” the wholesale price for capacity and energy by replacing the federal rate with a state-determined price.¹⁰ Second, they argued that these programs were unlawful under the Commerce Clause because they either explicitly (in Maryland) or implicitly (in New Jersey) restricted suppliers to certain geographical areas.¹¹

In each case, in wholly separate decisions, the district court judges ruled in favor of the plaintiffs on the issue of the Supremacy Clause.¹² In Maryland, the judge found that the Maryland procurement violated the Supremacy Clause of the U.S. Constitution because it “set” prices for sales of wholesale capacity and energy,¹³ and in New Jersey, the judge concluded the same.¹⁴ We will leave it to others to weigh these arguments from a legal standpoint. However, from our view as experts in economics and public policy, the arguments made by plaintiffs were unfounded and could have negative consequences for a host of state actions. Below we detail our four major concerns. 

States Face Long-Term Risks

Our first concern is that states will lose their long-held authority to order the construction of new generation – authority that no one else has under the Federal Power Act, including FERC.¹⁵ To understand why a state, even one that participates in a broader wholesale market like PJM, might order the construction of new generation, it helps to understand the real-world long-term risks that states face. These include the risks of: a) delayed transmission construction; b) large-scale generation retirements; c) abrupt changes in load forecasts, and d) the need to accommodate increased renewable generation. 

Maryland and New Jersey face many of the same risks. Both states rely heavily on imports of energy to meet their needs and, as such, are very much at risk for delays in the construction of new transmission lines. In fact, the motivation for Maryland’s Long-Term RFP occurred back in 2007 when PJM officials warned the state that a delay in the construction of two major lines (the TrAIL and PATH lines) could put the state at risk for shortfalls of up to 1,500 MW by 2012.¹⁶ The TrAIL line eventually was energized in 2011, but the PATH line was cancelled by PJM.¹⁷ New Jersey faced a similar situation. In 2009, PJM officials warned the state of reliability criteria violations by 2012 if a new transmission line (the Susquehanna-Roseland line) wasn’t completed by 2012.¹⁸ Officials from Public Service Electric & Gas raised the possibility of brown-outs or rolling black-outs if the line wasn’t completed on time.¹⁹ Due to permitting issues, the line was delayed, and is now due to be in service by 2015.²⁰

Second, both states rely on an aging fleet of generators at risk for retirement. New Jersey is expecting about 3,100 MW to retire by the middle of 2015; this represents about 18 percent of the existing capacity in the state.²¹ These retirements are driven by age and environmental restrictions. About 68 percent of these announced retirements in New Jersey are called High Energy Demand Day or HEDD units – older generators that have restricted operating ability because of environmental performance.²² (See Figure 1.) Maryland gets about 60 percent of its in-state generation from coal-fired units, and roughly two-thirds of Maryland’s capacity is more than 30 years old.²³

Third, both states are subject to swings in load forecasts that can be quite substantial. For example, the Maryland state-wide forecast peak demand for the year 2015 dropped more than 1,300 MW – nearly the size of three new combined cycle plants – between the years 2009 and 2010. Between 2010 and 2011, the peak forecast for the same year increased 452 MW – about the size of a new combined cycle plant.²⁴ These swings are more problematic when we consider that it takes at least three years to construct a new base or mid-merit power plant. 

Fourth, both states have aggressive renewable portfolio standards. These standards have brought forth – and will continue to bring forth – a great deal of intermittent resources whose varying levels of electric generation must be accommodated by other power plants; new natural gas-fired combined cycle plants are considered to be the best to provide such accommodation. Renewables can cause reliability problems, too. For example, in 2011 PJM found that 28,500 MW of renewable resources must be added to the system to meet RPS obligations by 2020,²⁵ and that such additions could move up the first occurrence of NERC thermal criteria violations for the transmission system by as many as five years.²⁶

We note that neither state has experienced major reliability problems thus far – mostly due to the recession, which significantly reduced demand, but also due to operational changes made by PJM.²⁷ Nonetheless, when decision-makers hear about blackouts in one year, and then are told not to worry the next, it doesn’t give them comfort. Commissioners, as decision-makers, don’t think that a significantly changed forecast means the forecast is getting more accurate. Instead, they see changing forecasts as indicative of the uncertainty of the future. In other words, changing forecasts don’t remove risk for a decision-maker, they reveal risk. 

In addition, we note that the judge in the Maryland case did affirm the state’s right to regulate the development, type and location of new generation within its boundaries.²⁸ However, at the same time the judge noted that the state couldn’t regulate or “set” the prices ultimately received by the generation for sales of its products on the wholesale market.²⁹ The problem with this restriction arises when power plants must be financed by long-term contracts that guarantee or set the ultimate price received for sales of capacity and energy – or are similarly guaranteed a set amount of cost recovery through rate-base treatment. Without the ability to guarantee a stream of revenue, states can’t guarantee that new generation will receive the financing needed and, therefore, can’t guarantee that new generation actually will be built.

Capacity Markets Serve the Short Term

PJM’s energy and capacity markets haven’t brought forth the diversified portfolio of resources needed to mitigate these four risks in transmission-constrained areas. Despite relatively high capacity prices in both Maryland and New Jersey, PJM’s capacity market had brought little new generation at the time of the state decisions, leading instead to a possible overreliance on limited resources such as demand-side measures.

PJM’s capacity market (the RPM) is designed to send locational price signals as an incentive to generators to locate in transmission-constrained areas. Both states have seen capacity prices that are significantly higher than in the rest of the PJM RTO. From the start of RPM until the issuance of the Long-Term RFP, the average price for SWMAAC capacity had been $177.04/MW-day, as compared to $88.65/MW-day in the rest of the RTO.³¹(See Figure 2.)This price premium was supposed to serve as incentive for new generators to build in constrained areas. However, when Maryland made its decision to issue the Long-Term RFP, it had seen only 242 MW of new generation selected in RPM since 2006, and that was fully offset by 788 MW of retirements.³²(See Figure 3.)At the time of the LCAPP decision, New Jersey had seen only about 534 MW of new generation made available through RPM.³³(See Figure 4.)

In contrast, over the same time frame the RPM has attracted a large number of other resources to Maryland and New Jersey that are operationally limited. Since RPM began in New Jersey, about 75 percent of new resources offered in the state have been either demand-response or withdrawn or cancelled retirements.³⁴ In Maryland, when the decision was made to issue the Long-Term RFP, about 1,800 MW of new demand response had cleared in the RPM auction.³⁵ Such operationally limited resources aren’t sufficient to mitigate the long-term risks noted above.

Demand response, for example, has a limited ability to contribute. For example, what PJM terms “limited” demand response only has to show up for a maximum of 60 hours per year;³⁶ in addition, it commits for just one year through RPM, and there’s no guarantee that it will show up in subsequent years. Similarly, many units are categorized as deferred retirements are older units, such as the New Jersey HEDD units; these can run for only a limited time due to environmental restrictions and will have to be shut down in the near future.³⁷ New generation, by contrast, can operate nearly around the clock and, once built, will be around for decades. 

States are still responsible for assuring reliability; it’s state commissions that field the (rightfully) angry calls from ratepayers when the lights go out. Given that, with so much uncertainty, it makes a great deal of sense for a state commissioner to turn to a solution based on getting steel in the ground – that is, ordering new generation to be built, as only states can do. 

Other Endangered State Programs

Our second concern with the plaintiff’s preemption argument is that it could wipe away a broad array of state programs, many of which might not appear threatened by these two decisions at first blush.

The plaintiffs in the two cases each argued that states can’t undertake any program which a) “affects” prices in a federal market; or b) “sets” a price for sales into a federal market by substituting a state rate for a federal rate. The latter argument is what the judges in both cases cited as the basis for finding that these programs violated the Supremacy Clause.³⁸ To see why this is such a dangerous argument, we need to step back and see how state policies really work. Typically, a state will say, ‘a) I want more of that kind of resource to pursue a particular policy goal; b) here is a guaranteed revenue stream to ensure the chosen resource gets built; and c) while that resource may participate in PJM markets, it receives its guaranteed revenue stream regardless of wholesale market prices.’ 

This formulation appears again and again in many types of state programs. For example, many states that have deregulated to allow retail choice offer full-requirements service for ratepayers who choose not to choose a competitive electricity supplier.³⁹ This service goes by many names, including “standard offer” and “provider of last resort” service. To select providers of this service, each state will have a competitive procurement in which wholesale bidders offer to serve a percentage of customer needs for a fixed price over several years. Even though these sales are often called sales for resale, state commissions approve the design of the procurement and the selection of winning bidders. Just as in the New Jersey LCAPP and Maryland’s Long-Term RFP, winning bidders can “affect” prices in PJM markets, and in the plaintiff’s logic, “set” a fixed price to be paid no matter what the wholesale PJM price may be. We are concerned that the outcome in the federal court cases could put all of these state efforts at risk. 

Another example can also be found in Maryland. In 2008, as part of its response to PJM’s warnings about the transmission construction delays noted above, the Maryland PSC conducted a procurement for demand response that had many of the same characteristics as the Long-Term RFP.⁴⁰ They invited just a single technology – demand-response products – required them to be located in Maryland, and offered a price guarantee to bidders via a contract for differences. Almost 400 MW of demand response was secured.⁴¹ We aren’t aware of objections by FERC or PJM to this procurement. 

Connecticut offers a third example. In 2007, the Connecticut Commission, concerned that New England capacity market prices had been at the cap of $14,000/MW-month, issued a procurement for new, in-state capacity that was almost identical to the procurements at issue here.⁴² It invited bids for peaking capacity that must be located in Connecticut. Winning bidders had to sign a contract to build a new plant and sell into wholesale markets, turning over all their revenues in exchange for a price guarantee. The procurement resulted in three new peaking facilities being built, about 500 MW of new capacity.⁴³ Again, we aren’t aware of any objections. 

A fourth example is the use of renewable portfolio standards, or RPS. Twenty-nine states and the District of Columbia have RPS⁴⁴ that dictate how much of the electricity supply must be generated by specific technologies. These jurisdictions encourage compliance with RPS through the use of renewable energy credits (RECs), which are given to renewable resources for generating power. RECs in effect set a price floor for renewable supply. What’s more, many states have long-term procurements for renewable supply which provide the type of long-term price guarantees that were offered in the Maryland and New Jersey procurements being challenged by the plaintiffs. 

Lastly, a fifth example can be found in traditionally-regulated states that supply the PJM market. For example, in Virginia, Dominion received approval from the Virginia Corporation Commission to construct a new combined cycle facility (the Warren County facility). Dominion was guaranteed a traditional cost recovery, but it will sell into PJM wholesale markets and will credit any market revenue it earns back to ratepayers.⁴⁵

All of these programs “affect” market prices by affecting supply and demand. All in whole or in part operate to “set” prices, in the plaintiff’s terminology, by offering a fixed revenue stream that insulates the resource from wholesale market prices. If this is no longer allowed, all these programs could be at risk for preemption. In addition, these programs often specify that a “local” product must be offered. For example, the Maryland “Gap” RFP and the Connecticut RFP required in-state location to ensure that the state ratepayers get what they were paying for.

Different Products, Different Programs

Our third concern with the plaintiff’s argument is that it fails to reflect the fact that what the commissions in Maryland and New Jersey are asking for is a different product than that procured in FERC’s wholesale markets. The PJM capacity market asks that a resource be available for one year, three years in the future, so a short-term product is being procured. In sharp contrast, both states are asking for a long-term product with a 15-to-20-year commitment. Moreover, these states ask a lot more from developers who must also actually construct a new power plant, operate that power plant, and offer that plant’s energy and capacity into wholesale markets for those 15 to 20 years.

Since these state programs are asking for a fundamentally different product, they’re creating a different market than FERC – a long-term capacity market tied to resource planning. It’s unreasonable to think that only the short-term market can exist, since short and long-term markets coexist everywhere. For example, in the housing market, there are renters and buyers. These are two different product markets. Buying a house is a long-term product. The buyer gets a guaranteed place to live and a guaranteed price in the form of a mortgage payment. The buyer, however, takes on the added risk of upkeep and a long-term financial commitment. Renting is a short-term product; a place to live isn’t guaranteed beyond the rental contract and neither is the price, and the risks of long-term ownership aren’t taken on. These markets are separate despite the fact that they “affect” each other. Buying a house that was a rental decreases the supply of houses for rent and could increase rental prices. Building too many houses for the long-term buying market could force a crash in the rental market if the new supply is converted into rentals. Despite this, no economist would propose shutting down the house-buying market to preserve a higher-priced rental market. 

Wholesale markets are FERC’s jurisdiction, but FERC realizes that state programs can coexist with wholesale markets and has taken measures to protect its wholesale markets. The key protection for the RPM market is the Minimum Offer Price Rule or MOPR. FERC itself has said the MOPR acts to “reconcile” state actions with FERC markets.⁴⁶ The MOPR scans new resources for below-cost bidding (or uneconomic entry). In practice, it sets a floor price for new gas-fired resources offering into RPM. Individual bidders may submit cheaper bids, but those bids must be reviewed by PJM and the Independent Market Monitor who will review the offers and determine whether or not they’re permissible and based on legitimate costs and revenue projections. The Maryland winning bidder’s unit and two of the New Jersey winning bidder’s units underwent this MOPR cost-review process and were selected to provide capacity in the 2015 and 2016 RPM Auction.

Acting on Price Signals

Our final concern with the plaintiff’s argument is that, by claiming that states can’t have locational requirements or preferences in a procurement, it ignores the fact that states are simply responding to FERC’s wholesale market design. With electricity, resources in one geographic location can’t serve everywhere at every moment because of constraints on the transmission system. PJM wholesale energy and capacity markets acknowledge this in their market design. When an area becomes constrained, it balkanizes; it has a separate price from other areas and, more importantly, new supply outside the constrained area can’t serve load in that constrained area. Because of this, it makes sense for state programs to ask for in-state supply so as to avoid paying for a resource from which ratepayers might not receive benefit. Otherwise, a state may end up paying twice for capacity; first, for the resource it selected in the competitive state-run RFP, and second, for the same amount of capacity from the PJM market.

An example might help illustrate how a state, if it ignores PJM’s locational price signals, could end up paying twice for capacity. Consider a scenario in which Maryland holds an RFP for new capacity and awards a contract for differences to a generator located in Maryland. The contract for differences price is $200/MW-day. Then assume that Maryland is a region within PJM that’s “constrained,” meaning it can’t import incremental capacity from outside due to transmission constraints, and that the clearing price for capacity in Maryland is $180/MW-day. Under the contract for differences, the Maryland ratepayers would pay the generator $20/MW-day and purchase capacity from PJM at $180/MW-day.

Now assume, in the alternative, that the winning bidder is located in western Pennsylvania, outside of the constrained region, where the clearing price for capacity is $120/MW-day. Under this scenario Maryland ratepayers again would have to cover the rest of the guaranteed contract for differences price, now $80/MW-day. In addition, because of constraints, the capacity of the western Pennsylvania generator isn’t actually serving Maryland load under PJM rules. Since the new generation is no longer in Maryland, the area must turn to higher-cost resources, raising the clearing price for capacity in Maryland to $195/MW-day. Thus, Maryland ratepayers pay a total of $275 – the $80 payment under the contract for differences plus the $195 capacity price. In this scenario the Maryland ratepayers pay for a resource in Pennsylvania that they don’t see the benefit of. This result could have been avoided simply by requiring the resource to locate in Maryland. 

States must be allowed to respond to the PJM and FERC rules that create the incentive to locate capacity where it’s needed most so the states can avoid forcing its ratepayers to pay too much for capacity. The states are only playing by the rules that FERC created. 

While the courts have, for now, accepted the plaintiff’s arguments, we hope that all parties will understand the risks that states face. States are in the best position to judge the risk tolerance of their ratepayers and each state can make its own assessment of how much to pay to mitigate the risks it faces.

States of course will take different paths. Massachusetts – faced with circumstances similar to those in Maryland and New Jersey – recently decided not to conduct a long-term capacity procurement.⁴⁷ More broadly, because of such difference among states, allowing the states to use long-run capacity procurements tied to resource planning will ultimately give America what it needs most: a diversified portfolio of resources to address the major uncertainties we face going forward as a nation.

Endnotes:

1. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013.

2. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 111-112; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 54.

3. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 113; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 64-65.

4. P.L. 2011, Chapter 9 (§§1,3,4 - C.48:3-98.2 to 48:3-98.4 §5 - C.48:3-60.1; LCAPP Law), Senate and General Assembly of the State of New Jersey, Trenton, NJ, Jan. 28, 2011.

5. In the Matter of the Long-Term Capacity Agreement Pilot Program (Docket No. EO11010026), New Jersey Board of Public Utilities, Order, March 29, 2011, 8.

6. “Notice of Approval of Request for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service(Case No. 9214), Maryland Public Service Commission, Sept. 29, 2011.

7. Maryland Public Service Commission, “Order No. 84815,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), April 12, 2012 (published by Public Utilities Reports at 297 PUR4th 336).

8. “Complaint for Declaratory and Injunctive Relief,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, April 27, 2012; “Complaint for Declaratory and Injunctive Relief,” Case 3:11-cv-00745, In the U.S. District Court for the District of New Jersey, Feb. 9, 2011.

9. “Complaint for Declaratory and Injunctive Relief,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, April 27, 2012, pp. 5-6, 30-31; “Complaint for Declaratory and Injunctive Relief,” Case 3:11-cv-00745, In the U.S. District Court for the District of New Jersey, Feb. 9, 2011, pp. 3-6, 25-27, 30.

10. “Trial Transcript,” Case 3:11-cv-00745, In the U.S. District Court for the District of New Jersey, March 4, 2013, 8.

11. “Complaint for Declaratory and Injunctive Relief,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, April 27, 2012, 34-36; “Complaint for Declaratory and Injunctive Relief,” Case 3:11-cv-00745, In the U.S. District Court for the District of New Jersey, Feb. 9, 2011, 31-33.

12. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 147; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 65.

13. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 111-112.

14. “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 54.

15. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 8; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 14-15.

16. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service(Case No. 9214), Boston Pacific Company, Jan. 23, 2012, 1-2.

17. “2010 Regional Transmission Expansion Plan Executive Summary,” PJM Interconnection, Feb. 28, 2011, 5 & 12; PJM Interconnection, L.L.C., “Comments,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service(Case No. 9214), Jan. 13, 2012.

18. “Pre-filed Direct Testimony of Steven R. Herling on Behalf of Public Service Electric and Gas Company in Support of Susquehanna-Roseland Transmission Line Project,” In the Matter of the Petition of Public Service Electric and Gas Company for a Determination Pursuant to the Provisions of N.J.S.A. 40:55D-19 (Docket No. EM09010035), Jan. 12, 2009, 4.

19. PSE&G warned New Jersey of blackouts if Susquehanna-Roseland wasn’t built on time: “If the [Susquehanna-Roseland] Project is not placed into service in 2012 … there will be overloads on critical circuits in the region, and PJM and the transmission owners may need to implement emergency operating procedures, such as reducing transmission system voltages (‘brown-outs’) or implementing rolling black-outs for network transmission service customers, in order to manage operating conditions.” See Pre-filed Direct Testimony of Esam A.F. Khadr on Behalf of Public Service Electric and Gas Company in Support of Susquehanna-Roseland Transmission Line Project, In the Matter of the Petition of Public Service Electric and Gas Company for a Determination Pursuant to the Provisions of N.J.S.A. 40:55D-19 (Docket No. EM09010035), Jan. 12, 2009, 22.

20. “Project Updates,” PPL, last modified Dec. 4, 2012; “Factsheet,” PSE&G, accessed July 30, 2013; PJM Interconnection, L.L.C., “Susquehanna-Roseland,” accessed July 30, 2013.

21. “Future Deactivations,” PJM Interconnection, last modified July 26, 2013;  “2014/2015 RPM Resource Model,” PJM Interconnection, Jan. 31, 2011; “2012 Quarterly State of the Market Report: January through September,” PJM Interconnection, Nov. 15, 2012, p. 226, sec. 11, tables 11-14; “2012 Regional Transmission Expansion Plan Report,” PJM Interconnection, Feb. 28, 2013, Book Five, sec. 8.

22. “Future Deactivations,” PJM Interconnection, last modified July 26, 2013; “2014/2015 RPM Resource Model,” PJM Interconnection, Jan. 31, 2011; PJM Interconnection, “2012 Quarterly State of the Market Report: January through September,” p. 226, sec. 11, tables 11-14.; “2012 Regional Transmission Expansion Plan Report,” PJM Interconnection, Feb. 28, 2013, Book Five, sec. 8.

23. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service(Case No. 9214), Boston Pacific Company, Jan. 23, 2012.

24. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service(Case No. 9214), Boston Pacific Company, Jan. 23, 2012, p. 20, table 7.

25. “2010 Regional Transmission Expansion Plan Report,” PJM Interconnection, Feb. 28, 2011, p. 75, sec. 4.

26. “2010 Regional Transmission Expansion Plan Report,” PJM Interconnection, Feb. 28, 2011, p. 78, sec. 4.

27. “Trial Transcript,” Case 3:11-cv-00745, In the U.S. District Court for the District of New Jersey, March 4, 2013.

28. “The Court agrees with Defendants’ position that the FPA preserved states’ jurisdiction over certain direct regulation of physical generation facilities. For instance, it appears that the states hold the authority to do the following: (1) take regulatory action to require existing generation facilities to retire; (2) limit the type or amount of generation facilities constructed in the state; (3) promote certain environmentally desired types of generation facilities; and (4) determine the siting or location of a new generation facility within the state.” “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 84.

29. “Where Congress intended FERC alone to regulate wholesale energy and capacity prices, and this Court has found the Generation Order sets or establishes the wholesale energy and capacity prices to be received by CPV for its sales into the PJM Markets, the PSC has encroached upon an exclusive federal field. In line with the principles of the Supremacy Clause, the Generation Order cannot stand.” “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 112.

30. “2008-2015 Base Residual Auction Results and Reports,” PJM Interconnection, 2007-2012.

31. “2008-2015 Base Residual Auction Results and Reports,” PJM Interconnection, 2007-2012.

32. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service(Case No. 9214), Boston Pacific Company, Jan. 23, 2012, p. 9, table 3.

33. “Comments of PJM Interconnection, L.L.C.,” In the Matter of the Board’s Investigation of Capacity Procurement Transmission Planning (Docket No. EO11050309), PJM Interconnection, June 17, 2011, 13.

34. “Comments of PJM Interconnection, L.L.C.,” In the Matter of the Board’s Investigation of Capacity Procurement Transmission Planning (Docket No. EO11050309), PJM Interconnection, June 17, 2011, 13.

35. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service(Case No. 9214), Boston Pacific Company, Jan. 23, 2012, p. 9, table 3.

36. “PJM Load Management,” PJM State & Member Training, PJM Interconnection, Jan. 4, 2013, 25.

37. New Jersey Department of Environmental Project, Division of Air Quality, Control and Prohibition of Air Pollution by Volatile Organic Compounds and Oxides of Nitrogen (R. 2009 d.137),March 26, 2009.

38. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 111-112; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 54.

39. Maryland Standard Offer Service, FirstEnergy and Duke Energy Ohio’s Standard Offer Service, Delmarva Power and Light’s Standard Offer Service, Pepco’s District of Columbia Standard Offer Service; and PPL’s, MetEd’s and PennElec’s Provider of Last Resort.

40. “Commission Staff Report and Recommended Gap RFP to be Issued by Maryland Investor Owned Utilities,” In the Matter of the Investigation of the Process and Criteria for Use in Development of Request for Proposal by the Maryland Investor-Owned Utilities for New Generation to Alleviate Potential Short-Term Reliability Problems in the State of Maryland (Case No. 9149), Maryland Public Service Commission, Dec. 22, 2008.

41. “Memorandum from Kevin Mosier – Data Request,” In the Matter of the Investigation of the Process and Criteria for Use in Development of Request for Proposal by the Maryland Investor-Owned Utilities for New Generation to Alleviate Potential Short-Term Reliability Problems in the State of Maryland (Case No. 9149), March 2, 2009; Maryland Public Service Commission, “Order No. 82511,” In the Matter of the Investigation of the Process and Criteria for Use in Development of Request for Proposal by the Maryland Investor-Owned Utilities for New Generation to Alleviate Potential Short-Term Reliability Problems in the State of Maryland (Case No. 9149), Maryland Public Service Commission, March 11, 2009.

42. DPUC Investigation of the Process and Criteria for Use in Implementing Section 50 of Public Act 07-242-Peaking Generation,” Connecticut Department of Public Utility Control, Decision, Dec. 14, 2007.

43. DPUC Review of Peaking Generation Projects,” Connecticut Department of Public Utility Control, Decision, June 25, 2008, 25.

44. “RPS Data,” Database of State Incentives for Renewables and Efficiency, accessed July 30, 2013.

45. For approval and certification of the proposed Warren County Power Station electric generation and related transmission facilities under § § 56-580 D, 56-265.2, and 56.46.1 of the Code of Virginia and for approval of a rate adjustment clause, designated as Rider W, under §56-585.1 A 6 of Code of Virginia (Case No. PUE-2011-00042), Commonwealth of Virginia State Corporation Commission, Final Order, Feb. 2, 2012 (published by Public Utilities Reports at 296 PUR4th 148).

46. FERC has made it clear that it believes markets under its jurisdiction can coexist with states’ long-term procurements: “We believe that the MOPR that we accept subject to modification in this proceeding, including the unit-specific review process proposed in PJM’s compliance filing, serves to reconcile the tension that has arisen between policies enacted by states and localities that seek to construct specific resources, and our statutory obligation to ensure the justness and the reasonableness of the prices determined in the RPM.” See: “Order on Compliance Filing, Rehearing, and Technical Conference,” 137 FERC ¶ 61,145, Nov. 17, 2011, ¶ 4.

47. “D.P.U. 12-77,” Investigation by the Department of Public Utilities on its own motion into the need for additional capacity in NEMA//Boston within the next ten years, pursuant to Chapter 209, Section 40 of the Acts of 2012 “An Act Relative to Competitively Priced Electricity in the Commonwealth” and pursuant to G.L.c. 164§ 76, Massachusetts Department of Public Utilities, March 15, 2013.

New York City, according to Sir Peter Hall’s epic 1998 survey, Cities in Civilization, is the “apotheosis of the modern.” Hall cites New York City’s unique geography as compelling technological fixes, and thus New York engineers invented the air brake (Westinghouse), the telephone (Bell), the electric light (Edison), the fountain pen (Waterman), the adding machine (Burroughs) and the linotype (Mergenthaler). Over time, cities age and sometimes ossify, as seen in Detroit. Cities have to reinvent themselves, and that reinvention includes their basic infrastructure: they have to renew roads, bridges, power lines, and water systems. 

Superstorm Sandy’s high winds and severe flooding revealed the fragility of New York City’s electricity infrastructure. Sandy was only the latest chapter in a prolonged review of the electric transmission system that has been underway since the Northeast Blackout of August 14, 2003. For more than a decade, the challenge has been where and how to invest intelligently in transmission. In the New York metro area, the challenge has been met in different ways by the different regulatory and political processes that govern transmission. Since 2003, in the New York City and Long Island area, only two major transmission projects – the Neptune and Hudson High Voltage Direct Current (HVDC) systems – have been commissioned and built. Connecticut, part of the New England power grid, has invested $1.9 billion in transmission projects. New Jersey, part of the mid-Atlantic power grid, has also added modestly to the expansion and renovation of its metro area transmission grid.

These references to different transmission grids highlight something distinctive about the New York metro area: New York is the only mega-city whose broader metro area is largely located, not only in other states, but also in other power pools. Seen from the “tri-state” perspective, the New York metro area’s transmission grid is defined by three completely different planning processes that determine what transmission must be built to keep the metro area’s lights on: in Connecticut, the process is administered by the Independent System Operator of New England (ISO-NE). New Jersey’s power grid is administered by the PJM RTO. New York City and Long Island’s transmission systems are administered by the New York Independent System Operator (NYISO).

An effort to amalgamate these three areas into a single ISO is now lost in the mists of time. Each RTO-ISO was spawned by efforts sponsored by the Federal Energy Regulatory Commission (FERC) back in the late 1980s and 1990s. The federal effort was motivated by the reality that electricity trade was inevitably an interstate activity, and hence ultimately under the purview of the federal government.

But, these regional transmission organizations have quite naturally focused inwards: they have spent the vast majority of their time managing the complex system of connections between electricity generation, transmission, distribution, and consumption within their respective footprints, not between regions. Thus, in spite of FERC’s prodding for better inter-area coordination, neither PJM nor ISO-NE nor NYISO have sponsored transmission projects between the regions. Even utilities that live on the borders have largely eschewed building transmission ties to neighboring control areas; thus the relative scarcity of transmission connections between Connecticut, New York, and New Jersey.

To the extent there are inter-regional projects, it’s been at the initiative of New York. New York’s electric authorities (the New York Power Authority and the Long Island Power Authority) have pioneered interconnections between the different electrical grids that serve the New York metro area: LIPA commissioned the 300-MW Cross Sound cable in 2001 that connects New Haven, Conn. to Shoreham, Long Island, and the 660-MW Neptune cable that connects Sayerville, N.J. to New Castle, Long Island. NYPA commissioned the 660-MW Hudson cable from Ridgefield, N.J. to mid-town Manhattan.

These projects have been developed by independent transmission companies, not the established electric utilities.¹ As such, these independents are in the vanguard of important changes in the U.S. electric transmission business. Even before the Northeast Blackout of 2003, it was widely agreed that hundreds of billions of dollars needed to be invested in the transmission sector.² FERC made it clear in word and deed that it wanted to encourage private capital as well as investor-owned and municipal utilities to make transmission investments. New York, New Jersey and Connecticut state political leaders shared in this sentiment, and the states either joined multi-state ISO-RTOs, or (in the case of New York) created a single-state ISO. 

The ISO-RTOs represent a major change in how the power transmission business in the United States is managed. They represent neutral, independent and non-profit platforms for managing the electric grid, and setting rules (with FERC oversight) on how new investments can be made and recovered. They administer electric markets with a variety of products: electric energy, reserve capacity, and other ancillary services need to keep the system operating within acceptable risk tolerances. By and large, the ISO-RTOs have done an admirable job creating a level playing field, and a coherent set of market rules under their “Open Access Transmission Tariffs” (OATT), their foundational documents. 

Nevertheless, if one was going to design a major metropolis from scratch, a central electric transmission design would probably rank as essential. Other than water, it’s hard to imagine a more important service to a metro area than electricity. And, since major metro areas are usually located within a single state, meaningful electric planning should typically be within the purview of the mayor of the city, the leaders of the suburbs, and the governor of the state the city is in. Thus, Los Angeles and San Francisco are squarely in California, Atlanta is in Georgia, Boston is in Massachusetts, and Chicago is in Illinois. While these great cities may spill over into neighboring states, the great preponderance of each metro area lies within its “home” state, and the electric planning of that state can totally accommodate the electric needs of its great metro area. Especially in these days of eco-oriented city planning, this alignment of views on how to power the city and the suburbs is an important activity.

This isn’t possible in the New York metro area. While the bulk of the metro area economy is in New York City, the components contributed by the New Jersey and Connecticut portions are very substantial indeed. If the “gross domestic product” of the New York metro area is $1 trillion, as is often claimed, then surely the Connecticut and New Jersey portions must be reckoned in the hundreds of billions of dollars of economic activity.³ Yet, the electrical systems of the three parts of the metro area are barely connected. It’s as if economics were never consulted when the metro area grid was laid out. 

The electrically “congested” parts of the metro area have included Long Island, New York City, southwest Connecticut, and northeastern New Jersey. The need and therefore the pressure to de-congest the metro area, however, came initially from Long Island, a unique geographic area of 7. 5 million people, a 5,500-MW peak load, a disastrous nuclear power plant investment in the 1990s, and electrically as easy to connect to Connecticut and New Jersey as to upstate New York. By 2007, the Long Island Power Authority had taken the lead to get two transmission projects built (the 300-MW Cross Sound Cable and the 660-MW Neptune projects) which presaged the beginning of the end of Long Island as a load pocket. A few years later, the New York Power Authority followed suit by selecting the 660-MW Hudson project to connect PJM to New York City. 

These projects – designed as sophisticated, controllable, inter-area HVDC systems – could have opened the door for transmission to shatter the destructive load pockets of the metro area, and to integrate New York City and Long Island fully into the neighboring PJM and New England markets. But a regulatory development intervened, and threatens to stop the development of transmission as a solution to the metro area’s electric congestion issues.

Revenge of the Urban Generators

No tectonic shift can occur in the electric topography of the New York metro area without a challenge from those who have invested in the expectation that load pockets are forever. In this case, the challenge has come in the details of the NYISO’s “capacity regulations.” These regulations came out of an intense and protracted series of discussions and negotiations between New York electric “stakeholders” in the latter part of the first decade of the 2000s. 

To explain what happened requires a quick review of how the NYISO works. Under FERC rules, the NYISO can propose amendments and refinements to its foundational document (the OATT), but FERC disposes approvals and denials. For a period of several years culminating on Sept. 27, 2010, the NYISO labored over the outlines of a series of rules that would ultimately be called “market power mitigation measures applicable to the New York City (in-City) Installed Capacity (ICAP) market.”⁴ Its effect, if not its intent, was to protect New York City generators from enhancements to the transmission system that would eliminate the conditions that gave rise to the load pocket in the first place. 

The original regulations for the New York ISO’s “capacity” (e.g., ICAP) market created a periodic auction of the existing and proposed capacity, with minimum and maximum bid prices in New York’s three designated capacity zones (New York City, Long Island, and the rest of the state). The intent was to protect buyers against market power and predatory pricing by generators (hence the need for a ceiling price for capacity services), and to protect generators against monopsony power in the form of efforts by utilities and authorities to subsidize new generation and thus drive the price down (hence the need for a floor price for capacity services). To qualify as capacity resources and earn capacity revenues, new projects had to qualify as a “competitive entrant.” The tortuous language selected for this assignment was “NET CONE” with CONE an acronym for Cost of New Entry. The effect of these regulations on New York capacity prices is shown in the charts on the previous page. In both charts, the price of capacity is reflected on the vertical axis. At equilibrium, capacity exactly matches requirements. In that case, the payments to a generator in the NYCA (essentially, the upstate) market in 2011 was $8.86 per kilowatt (kw) per month; in New York City, the payment at equilibrium was $16.91 per kw per month. The higher payment in New York City is supposed to reflect the fact that it costs much more (perhaps two to three times more) to build a generator in New York City than it does in upstate New York (or New Jersey, for that matter). 

As usually happens in these types of regulatory constructs, the devil is in the details. The key parameters are: 1) the definition of what constitutes a competitive entrant; 2) how the price floor is calculated; and 3) how the ceiling is calculated. As shown in the chart, these constructs were embedded into what’s called a “demand curve” for capacity that allows the capacity price to go up and down between the floor and ceiling, in response to the changes in the balance between supply and demand (the percentages on the horizontal axis are defined levels of surpluses, with 100 percent being exactly the amount required). The floor and the ceiling are determined in reference to the cost of a theoretical new generating unit, Net CONE. The floor was set to protect generators against subsidized competitors at 75 percent of Net CONE. With these mechanisms, the NYISO prepared itself to subject projects to a Mitigation Exemption Test (MET). If a project was exempt, it could participate in the capacity market without restrictions. If it wasn’t exempt (if it was deemed “uneconomic”), it would be prohibited from participating the capacity market for a defined period of years. Such a prohibition would cost the project tens of millions of dollars per year in revenue. (See Figure 1).

Whatever one’s opinion of this construct for generation qua generation, the NYISO first applied this construct to a transmission line in 2012, with potentially severe consequences for the metro area. 

The Larger Issue

In 2012, the NYISO ruled that the Hudson Transmission Project (a 660MW HVDC project selected by NYPA in a competitive RFP, and constructed in 2011-2013) was “uneconomic” and therefore would be subject to the MET. HTP subsequently lodged a complaint with FERC arguing against this ruling, but HTP based its argument on relatively narrow grounds pertaining to timing and the exact figures to use in the MET.⁵ HTP’s complaint didn’t raise the larger issue of whether the MET should be applied to a new transmission line at all. Is it appropriate – even in principle – to apply the MET to new transmission lines? Is there a basis in logic, FERC precedent, or economic theory for treating transmission like generation? 

The basic facts are these. HTP entered the NYISO interconnection queue in 2005 and won the NYPA RFP in 2006, years before NYISO’s buyer market power mitigation rules and the MET had been proposed. The NYISO first proposed the MET in 2007⁶ and later proposed to apply the MET to transmission lines, as if transmission were equivalent to new generation, without providing any details or discussion of how it would implement the MET for transmission or any justification for its proposal. The FERC order accepting the NYISO’s proposal to apply the MET to transmission included only a cursory discussion of the proposal, and didn’t address any of the potential policy issues, or the logical peculiarities, of the NYISO’s proposal.⁷ After the commission accepted the NYISO’s proposal, the NYISO didn’t provide any further details as to how it would apply the MET to new transmission lines until four years later, in mid-2011, and only then on a confidential basis to Hudson Transmission. 

NYISO’s application of the MET to transmission was puzzling. Simply stated, a transmission line isn’t a generator. By treating a transmission line as if it were a generator, the NYISO simply failed to recognize the fundamental differences between generation and transmission. Such an error isn’t all that common in the regulatory arena, and its appearance here was perhaps more an act of omission than commission. Clearly, it’s erroneous to equate agents of production (a generator) with agents of transportation (transmission). Transmission lines aren’t generators. Generators create electricity; transmission lines convey electricity from one point to another. 

When evaluating what kind of regulatory error this is, it may be best to rely on simple logic. It was recognized long ago that authorities can commit what are now called category errors: “a category mistake arises when things or facts of one kind are presented as if they belonged to another.”⁸

Thus, it seems plain that the NYISO committed a category error when it looked upon Hudson Transmission and assumed it was part of the category “generators,” rather than in the category “controllable transmission infrastructure,” which is complex system for conveying energy, capacity, and ancillary services from one electric area to another. To compound the error, the NYISO treated the Hudson Transmission Project as a “generator lead line” that provides electric energy, capacity and ancillary services from one specific generator to a specific point on the NYISO system. But the Hudson Transmission Project isn’t a generator lead. It’s a high-tech, controllable, system-to-system connection between the entire PJM system and the NYISO system. HTP will continue to operate whether or not any particular generator is on or off. Like the road to the mall, it’s in the category of infrastructure. A road connected to a mall doesn’t close just because a store in the mall closes; it remains open. 

Moreover, a generator is a market participant, a producer and supplier of electric energy and capacity, while a transmission line like HTP is not. Hudson Transmission will earn revenues merely from providing transmission service, and its costs for doing so are based on the cost of construction, rather than the marginal costs of fuel. Thus, the cost and revenue streams for new generation and new transmission projects are fundamentally different. Given these different cost and revenue streams, the concept of “uneconomic entry,” as embodied in the NYISO’s current rules, can’t be meaningfully applied to transmission lines. 

Moreover, transmission can provide enormous system-wide reliability benefits of a different nature than those provided by generators. In particular, under New York rules, if a transmission project can’t clear the ICAP auction, the inherent attributes of the transmission line enable the NYISO to use the line to reduce the Installed Reserve Margin (IRM) for NYISO and the Minimum Locational Capacity Requirement (MLCR) for New York City and Long Island. By contrast, if a generator in New York City is unable to clear the capacity markets, it isn’t available to be used by NYISO to reduce the IRM or MLCR.

Equally important, the FERC applies different standards to evaluate and mitigate generation and transmission market power. The commission recognizes these fundamental differences between generation and transmission, as reflected in the fact that it applies different standards for evaluating and mitigating generation and transmission market power, respectively. The commission assesses generation market power through market share, pivotal supplier, or delivered price tests that are based on the amount of generation owned or controlled by a generator and its affiliates in a given market, and generators that fail those tests are mitigated by applying cost-based offer caps or similar mitigation. The commission normally assumes that a regulated transmission provider with a franchised service territory (i.e., a non-merchant transmission line) has market power by virtue of the fact that transmission is assumed to be a “natural” monopoly. Consequently, the commission addresses this by requiring such transmission providers to provide service under an open access transmission tariff (OATT) or through transferring operational control to an ISO-RTO (as Hudson Transmission has done). Service over the Hudson Transmission line will be provided under the terms of an ISO-RTO OATT, and it’s therefore inappropriate to impose additional mitigation on Hudson Transmission. 

Moreover, for merchant transmission providers such as HTP, the commission applies a four-prong test to evaluate requests for negotiated rate authority. To pass this test, the merchant transmission provider must demonstrate, among other things, that the line won’t be located in the footprint of its own, or an affiliate’s, franchised service territory, that it won’t have the ability to exercise market power (instead it turns operational control over to an ISO-RTO), and that it can’t engage in undue discrimination or affiliate abuse. In addition, HTP committed that it wouldn’t sell energy or capacity in the NYISO market. The commission determined that Hudson Transmission satisfied these requirements, and therefore Hudson Transmission wouldn’t be subject to additional mitigation as if it were a generator. 

Returning to the conceptual categories of philosophy and logic, it would appear that the NYISO further compounded its category error by committing a “composition fallacy,” which occurs when the conclusion of an argument depends on an erroneous characteristic from parts of something to the whole or vice versa.⁹ By assuming that Hudson Transmission is, in effect, part of a generator, it attributes to Hudson Transmission only the attributes of a generator. But Hudson Transmission on its face is far more than a generator. It’s a controllable transmission line that conveys the products of multiple generators, indeed the essential strength and stability of the entire PJM system (whose total value is far more than the sum of its generator parts), across the Hudson River, to New York City. 

Unintended Consequences

The MET regulation, while highly technical, has huge implications for the New York metro area. If the MET continues to be applied to transmission in New York City,¹⁰ it will prevent projects from being built or it will render existing projects uneconomic by eliminating significant revenue streams. In the New York metro area, transmission development is already incredibly difficult and demanding. Of the major new transmission projects commissioned since 2000, a total of 1,290 MW have used ultra-sophisticated HVDC and VFT technology. In New York City, one major and extraordinarily difficult AC project has been built since 2000. Consolidated Edison maintains the complex urban transmission and distribution systems that serve Westchester County, the Bronx, Manhattan, Queens, Brooklyn, and Staten Island. Due to the density of the population, most of ConEd’s wires are considered part of a massive distribution system, not part of a transmission grid.¹¹ ConEd’s largest transmission project is called M29, and the description of its route through city streets is a monument to the difficulty of building transmission from the north to the south in the greater metro area.¹²

FERC policy and precedent have consistently promoted the development of economic transmission infrastructure projects designed to reduce congestion and price differentials between different markets or pricing zones. As a result of the NYISO’s application of the MET to Hudson Transmission, the HTP won’t be able to supply the NYC market with capacity, unnecessarily depriving ratepayers of the resulting savings. Application of the MET’s presumption of illegitimate or illegal intent to new transmission projects will block the development of many beneficial projects that can deliver lower-priced generation to load, thereby lowering costs to consumers.

How do we prevent the damage this category error will wreak? And then how does the New York Metro Area finally get the transmission it deserves? It starts with FERC. In addition to granting the relief requested in the HTP complaint, the commission should direct the NYISO to revise its Attachment H to eliminate the provisions applying the MET to new controllable transmission lines, and to subject such new projects to Offer Floor mitigation in the event they fail the MET. With that, New York, Connecticut and New Jersey can get on with the continued development of critical intra-metro-regional transmission projects. New York Governor Andrew Cuomo launched a New York “Energy Highway Initiative” in 2012 that holds particularly great promise for starting the New York side of this program.¹³

New York’s regulators can also make important contributions. While electric transmission is deemed an interstate activity, and hence is regulated by FERC, for decades now federal energy policy has lacked a vision for the nation’s energy infrastructure. The United States doesn’t have a national electricity policy, other than what is expressed in a series of discrete orders issued by FERC over the last several decades. FERC’s support for private investment in transmission is part of its long-standing campaign to restructure the electricity industry that goes back decades. 

In Search of Vision 

New York, however, has a clear vision about its energy future.¹⁴ And its regulators have always occupied a prominent position in the evolution of American utility regulation. At the beginning of the 20^th century, “the regulatory ideology of elite Progressives first saw application within the electric utility realm in Wisconsin and New York during the first decade of the twentieth century…. Their successful passage of laws in two states created a model for policymakers elsewhere to emulate.” Decades later, it was Alfred Kahn’s chairmanship of the New York Public Service Commission from 1974 to 1977 that championed basing regulations on sound economic principles.¹⁵

Today, the heaviest burden of the campaign to bring order to the electrical future of the New York metro area falls on Governor Andrew Cuomo, the Public Service Commission, the city of New York, and those responsible for the future electric development of Long Island. But New Jersey and Connecticut should be part of the discussion. The resolution to the present and future congestion issues of the tri-state metro area requires collaboration from all three states, and the power pools to which they belong. Unnecessary impediments, such as the application of the MET to interregional transmission projects, must be removed as quickly as possible. Then, based on a sound regulatory foundation, and tri-state metro area planning, transmission projects can be enabled that will make the metro area a robust hub of economic growth that will benefit all three states.

Endnotes:

1. Krapels was a principal with the companies that developed the Neptune and Hudson projects.

2. From the U.S. Department of Energy’s National Transmission Grid Study: “There is growing evidence that the U.S. transmission system is in urgent need of modernization. The system has become congested because growth in electricity demand and investment in new generation facilities haven’t been matched by investment in new transmission facilities. Transmission problems have been compounded by the incomplete transition to fair and efficient competitive wholesale electricity markets. Because the existing transmission system wasn’t designed to meet present demand, daily transmission constraints or “bottlenecks” increase electricity costs to consumers and increase the risk of blackouts.”

3. See http://www.bea.gov/newsreleases/regional/gdp_metro/2013/pdf/gdp_metro0213.pdf for a review of GDP by metropolitan area.

4. The seminal FERC Order was issued on November 26, 2010. See FERC Docket No. ER10-3043-000.

5. See “Complaint Of Hudson Transmission Partners, LLC,” Attachment 7, FERC Docket EL12-98.

6. See FERC Docket No. EL07-39.

7. New York Independent System Operator, Inc., 122 FERC ¶ 61,211 (the “March 2008 EL07-39 Order”), on reh’g and compliance, 124 FERC ¶ 61,301 (2008), on reh’g, clarification & compliance, 131 FERC ¶ 61,170 (2010) (the “May 2010 EL07-39 Order”).

8. From Simon Blackburn in the Oxford Dictionary of Philosophy.

9. A simple Wikipedia example: “This fragment of metal cannot be fractured with a hammer, therefore the machine of which it is a part cannot be fractured with a hammer.” This is clearly fallacious, because many machines can be broken-apart, without any of those parts being fracturable.

10. It hasn’t yet been applied in zone K, the Long Island zone.

11. Typically, the distinction between transmission and distribution is defined by voltage levels: anything below 69kV is considered distribution.

12. See ConEd’s Article VII permit application at http://www.coned.com/publicissues/M29_PDF/Text/Exhibit2Location_Facilities.pdf

13. http://www.nyenergyhighway.com/

14. See Governor Cuomo’s Energy Highway Blueprint and the Update on http://www.nyenergyhighway.com/PDFs/BP2013/EHBPuploadpt2013/.

15. Richard F. Hirsch, Power Loss: Origins of Deregulation and Restructuring in the American Electric Utility System (Cambridge: The MIT Press, 1999), p.19. More generally, among many competent histories are Thomas P. Hughes, Networks of Power: Electrification in Western Society, 1880-1930 (Baltimore, Md.: The Johns Hopkins University Press, 1983).

On December 13, the day ITC gave up on buying Entergy’s multi-state transmission network (three days after Mississippi regulators had scuttled the deal) Fortnightly spoke with Linda Blair, ITC’s executive v.p. and chief business officer:

“This was in no way a transaction we needed to do,” said Blair.

“Our pipeline is still pretty full.”

As evidence, Blair cited the Thumb Loop line in Michigan, now nearing completion, and also its “V” Plan in Kansas, as examples of ITC key grid projects still moving ahead.

“That’s a testament to our model,” she noted, “to our singular focus on transmission.”

And Blair is probably right; ITC likely can prosper without Entergy’s lines. But can we say the same for the power industry as a whole, and for the Federal Energy Regulatory Commission? Because with this deal’s rejection, FERC comes out the big loser.

FERC has long promoted the Transco concept – one company owning nothing but transmission – as a useful adjunct to its vision of market-based pricing. And Justice Department’s Antitrust Division had said back in 2012 that if Entergy would spin off its lines to form a Transco, it would refrain from taking action to address allegations that Entergy had used its monopoly control to foreclose rivals from obtaining long-term firm transmission service. But the December 10 ruling by the Mississippi Public Service Commission consigns any would-be Entergy Transco to the trash heap.

The Mississippi opinion features a 20-page retrospective on the history of the Transco model – how various state commissions have dealt with Transco proposals over the years (GridFlorida, etc.) – that concludes with Mississippi PSC clearly rejecting FERC’s thesis that discrimination in transmission service provided by a vertically integrated utility justifies consideration of the Transco model:

“[A] ‘perception of bias’ is not proof of bias …,” as the PSC states.

“ITC’s independence is touted as a virtue, but approval of the transaction would leave ITC independent of [the PSC] and the local concerns of Mississippi ratepayers, the economy and the State.”

On first glance, perhaps, the PSC ruling appears to draw on public interest principles – calling the deal bad for ratepayers after crunching the numbers – to justify the decision to flatly reject any transfer of T lines from local utility Entergy Mississippi Inc. (EMI), to ITC Holdings, the out-of-state grid conglomerate. Despite claims by ITC that its single focus on transmission would yield benefits, the state commission remained unconvinced: “the benefit to Mississippi ratepayers,” it wrote, “is dubious.”

The PSC explains, rightly, that if the local utility sells off its transmission lines used to serve native load – unbundles them from retail distribution – then ratemaking authority passes to FERC. That means a higher revenue requirement, forged from generous federal grid incentives and a higher, federally authorized return on equity. The Mississippi commission finds that a selloff of grid assets to ITC could cost Entergy ratepayers at least $348 million over 30 years.

“We must view the proposed transaction for what it is,” the PSC declared: “an attempt by Entergy and its shareholders to monetize its transmission assets and extract the excess value.” (See, Energy Mississippi, Inc., Miss. PSC No. EC123-0082-00, Joint Application for the Transfer of ownership and Control of entergy Mississippi Inc.’s Transmission Facilities, Final Order, Dec. 10, 2013.)

But as a law school professor might lecture his first-year class of budding lawyers, all this is just dicta – rich-sounding words added for effect that don’t really control the result of the decision. By contrast, in the strictest legal analysis, the Mississippi decision, if we read it by its own terms, doesn’t actually turn on a dollar-and-cents weighing of costs and benefits.

For if that were true, the case might well have swung the other way. And in fact ITC had anticipated the problem – that the deal appeared overly generous to ITC and Entergy stockholders – and so had offered a sweetener to even things up.

As ITC’s Blair told Fortnightly,“we and Entergy had put forth a rate mitigation plan to hold state ratepayers harmless until such time [in ‘perpetuity,’ if need be] as we could demonstrate benefits stemming from our Transco model.

“But the PSC did not give due consideration to our offer.”

Rather, the PSC’s decision draws a line in the sand, regardless of numbers. It declares premptive war on any attempt to divert ownership of local utility T lines to out-of-state control. It stands as wholesale repudiation of FERC policy: a defense to the death, if you will, of the traditional utility model of generation, transmission, and distribution, all under one roof.

Mississippi’s commissioners could just as easily have climbed up the courthouse steps and declared, “vertical integration today, vertical integration tomorrow, vertical integration forever.”

Let’s read the fine print. On pages 21 and 22 of the 90-page opinion, the PSC explains that “prior to a public interest finding” – i.e., before you ever get to the cost-benefit analysis – you must first satisfy a “statutory prerequisite” laid down by the state legislature back in 2003 that, according to the state commission, mandates vertical integration for Mississippi’s electric industry: now and forever.

That legislation (Miss. Code Annotated, sec. 77.3-23) states that if a merger or sales transaction involves transmission facilities included in a utility’s rate base, the state commission must first find – before crunching numbers – that after the deal’s close, all native load customers will “be served on the same basis as before the transaction.”

The state legislature has never truly defined what that means. But with its December 10 ruling, the state commission now has. According to the PSC, “served on the same basis” means that transmission service must be provided after the deal according to “an equivalent foundation or framework” as had existed beforehand: which in this case means through grid assets owned by the retail utility and bundled with retail energy distribution service.

Thus the PSC ruling declares, in so many words, that no sale or merger deal involving transmission can pass muster in Mississippi, nor ought to, if at the end of the day, the retail utility will no longer remain vertically integrated, with transmission owned under the same roof as generation and distribution.

But here we should be clear: the Mississippi commission still wants to go forward with Entergy’s integration into MISO, the Midcontinent ISO.

The key lies with MISO’s special “bundled load” exemption, which in this case will preserve state PSC authority to set the transmission revenue requirement, provided that grid assets remained under ownership of the load-serving utility. 

With Entergy joining MISO, the PSC notes, the cost of energy for the typical EMI ratepayer likely will fall, but with the state commission still retaining rate-setting authority over bundled transmission. And so the Mississippi commission finds no cause to oppose EMI’s integration into MISO.

That move, set for the middle of last month, appeared still on target at press time. Yet hearts were set aflutter in October, when the Missouri PSC said it would block integration into MISO of transmission assets held by Entergy Arkansas Inc. (EAI), but located in Missouri’s “Boot Heel” district, unless EAI somehow could bring the Midcontinent ISO to the negotiating table with Southwest Power Pool to hammer out a revised joint operating agreement to address loop flow issues arising from Entergy’s join-up with MISO – a feat clearly beyond EAI’s capacity to deliver, and something that even FERC had said it wouldn’t require.

The Missouri commission “withdrew” that order six weeks later, clearing the way for EIA to join MISO, and closing the case effective December 10. (See, Mo.P.S.C. File No. EO-2013-043, Report and Order issued Nov. 26, 2013.)

But as the PSC noted, Entergy’s transfer of functional grid control to MISO would have been found not in the public interest had the commission looked only at effects on those Missouri ratepayers who wouldn’t be joining the RTO.

• • •

Here’s food for thought: Is one negawatt as good as another? Are negawatts fungible, like kilowatt-hours?

Late last year, in a case involving the New York ISO and brought by EnerNOC, Viridity, Comverge, and EnergyConnect (a Johnson Controls company), FERC settled the issue once and for all (with Commissioner Moeller dissenting) that electric consumers who operate customer-owned generation behind the meter can sell demand response into day-ahead energy markets run by RTOs, and can receive the full locational marginal energy price (the LMP) as compensation, as guaranteed by FERC Order 745. (Dkt. EL13-74, Nov. 22, 2013, 145 FERC ¶61,162.)

EPSA (the Electric Power Supply Association) and others have long opposed the idea, complaining that customers ought not have their cake and eat it too – that a customer who self-generates behind the meter isn’t really going without.

Rather, that customer is simply going off the grid – taking power maybe from the back yard, and perhaps firing up a high-polluting diesel unit in the process, meaning that a BTM-backed DR resources is just about the un-cleanest resource in the RTO dispatch stack.

This argument – that full LMP for DR invites dirtier resources into the mix – has appeared in pleadings filed D.C. Circuit, where EPSA’s appeal of FERC Order 745 was yet pending at press time. (See, EPSA v. FERC, DC Cir Case Nos. 11-1486, filed Dec. 23, 2011, oral argument held Sep. 23, 2013.)

FERC’s rationale in defense is simple. The commission says that the exact manner in which a customer is able to produce a load reduction from the assumed baseline level doesn’t matter. The reduction can come through shifting production, consuming less electricity, or even from internal (BTM) generation – the last of which is not really a negawatt at all.

In other words, in energy markets, DR resources are fungible. A kilowatt-hour of generation is every bit as good as negawatt, and vice versa.

But let’s consider the issue in the context of capacity markets.

Phantom Virtual Capacity

Lately PJM has become concerned about the problem of DR “replacement” bids for commitments to its regional capacity market, the RPM (Reliability Pricing Model). The fear is that DR suppliers are speculating, submitting over-ambitious bids in the three-year-forward base residual auction, but then attempting to buy out their positions in future incremental auctions as the time for delivery draws closer, either cashing out or perhaps attempting to substitute a replacement resource for the original DR bid.

And PJM isn’t simply saying that X amount of demand resources is too much. Rather, it’s increases above previously established demand response levels that “are so great that they should be viewed with caution … to ensure that increases above prior levels have … specific identified physical support.”(PJM, Reply Comments, pp. 3-4, FERC Dkt. ER13-2108, filed Dec. 11, 2013.)

Andrew Ott, PJM’s senior v.p. of markets, described the problem in a statement filed at FERC in November, following a technical conference held at FERC in October to hash out differences over a new tariff filed by PJM in August to change the way DR resources must bid into the RPM:

“With clearing prices frequently lower in the incremental auctions than … in the base residual auction for the same delivery year, some market participants evidently perceive a seemingly cost-free opportunity to take a position in the BRA that they hope to buy out at lower cost in the incremental auctions.”

And Ott isn’t complaining in the abstract about too much DR swamping the capacity market: “PJM’s reliability concern is not with zones with ‘high DR penetration’ … rather, with zones that have DR offers far above levels cleared in previous auctions in those zones.” (Statement of Andrew Ott, pp. 1,15,  FERC Dkt. ER13-2108-000, filed Nov. 8, 2013.)

PJM’s independent market monitor Joseph Bowring has complained of the same thing, pointing out that sellers of demand resources in RPM auctions tend to replace those commitments disproportionately compared to sellers of other resource types:

“These replacement transactions may have covered non-physical offers that the seller hoped to cover with a future physical procurement. In other cases, these replacement transactions may have covered non-physical offers based on speculation about relative prices in the BRA and IAs, and there never was a bona fide plan to make them physical. It is difficult to distinguish the motives if the seller is not a purely financial entity, but persistent high levels of replacement capacity purchases by sellers of DR is consistent with a role for both explanations.” (Answer of IMM, p. 2, FERC Dkt. ER13-2108-000, filed Sep. 13, 2013.)

As Bowring continues, “RPM was designed to procure a physical capacity product. This requires an offer of a specific physical resource including a specific location.”

In other words, as PJM says, “capacity is not a fungible commodity.”

To address this problem, PJM proposed a new tariff back in August to change the way suppliers of DR resources must submit bids into the regional capacity market.

Under this proposal, demand response bidders in the capacity market must fill out a new “template” for what it calls a DR Sell Offer Plan. As proposed by PJM, DR bidders in capacity markets would be required to provide, among other things: (1) the DR provider’s name, contact information, and intended offer, identified by MWs, DR value, zone and sub-zone; (2) all end-use customer sites expected to participate as of the delivery year; and (3) key assumptions underlying the planned offer, including types of customers targeted and methods of achieving load reductions at certain customer sites. (FERC Dkt. ER13-2108, filed Aug. 2, 2013.)

These new requirements have drawn a fierce protest from Comverge, a curtailment services provider in PJM. For one thing, Comverge targets PJM’s proposed requirement that DR providers must submit an officer certification verifying the DR provider’s intent to deliver the same promised demand resources that it bids into the BRA. Comverge protests further that PJM is requiring corporate officers to predict the future.

Frank Lacey, v.p. for regulatory and market strategy for Comverge, explains in comments filed with FERC:

“None of the current certifications required an attestation to expectations about future events or forward-looking statements.

“In stark contrast, the proposed tariff revision requires that the officer attest to an expectation that a DR provider will physically deliver all of the stated megawatts three years in the future.” (Comverge, Post-Conference Comments, pp. 10-11, FERC Dkt. ER13-2108, Dec. 3, 2013.)

Lacey argues that the true problem stems from a “broken” capacity market:

“PJM’s real concern is that capacity markets are not producing correct clearing prices.”

PJM defends its proposal to offset the risk that multiple DR offers might be relying on load reductions from the same end users. P3, the PJM Power Producers, agrees, noting that PJM’s reliance on DR to meet reliability targets has grown as DR has displaced existing generation in the supply stack:

“If resources are allowed to bid speculatively in BRAs,” say the power producers, “without demonstrating some reasonable likelihood that they will be physically deliverable, resource adequacy may be jeopardized.” (P3, Post-Conference Comments, p. 4, Dkt. ER13-2108, Dec. 3, 2013.)

But note how this vision differs from the bid-based, system-constrained regional energy markets run by RTOs. In both the day-ahead and real-time bidding, neither generation nor capacity are considered to be purely physical. Virtual bidding is permitted. Traders with a day-ahead position can adjust risk with a counterbalancing real-time bid, or chose later to cash out or cover their positions, like a short seller in the stock market. Transmission becomes a financial right, with traders “buying through the congestion” to overcome the grid’s physical limitations by paying a location-based generation price where necessary in order to secure a resource at a location where delivery would be impossible to guarantee under a regime of physical rights.

Why shouldn’t DR bidders also be allowed to settle their capacity commitments financially, in the same manner as in energy markets?

For this question Comverge and Lacey have a ready answer:

“The purpose of the RPM,” it argues, “is to ensure sufficient physical capacity to meet load-serving obligations in the delivery year.

“Any entity offering capacity resources into an RPM auction should do so with the expectation that it will meet its obligations with physical capacity, whether from generating resources, conservation, or DR resources. The market should be indifferent as to the type of physical resource that provides this capacity.” (Frank Lacey, Comverge, Post-Conference Comments, p. 12, FERC Dkt. ER13-2108, filed Dec. 3, 2013.)

For demand response aggregators like Comverge, the business is all about probabilities – about reasonable expectations of future customer behavior.

Perhaps it’s worth noting that two years ago, in this column, we reported on how the noted DR advocate Donald Sipe, an attorney representing EnerNOC at that time, had urged FERC to take a more dynamic view for DR bid into regional capacity markets.

Sipe had argued that capacity markets ought to reward customers for a guaranteed load drop (GLD), whether individually or across an aggregated portfolio of customers and resources, even if greater than the customer’s (or the group’s) baseline – past contribution to system peak load, known in PJM as PLC, which ordinarily falls during the summer. (See, “Yes, We Have No Negawatts,” Fortnightly, Oct. 2011.)

FERC rejected Sipe’s arguments, however, holding that the essence of demand resources isn’t absolute size, nor the scope of its dynamic reduction in load. Rather, a negawatt has capacity value only if it diverts from the expected baseline – only if it frees the grid from having to serve the level of load that the system has already committed to serve, as evidenced by the manner in which it’s been funded and built. (Dkt. ER11-3322, Nov. 4, 2011, 137 FERC ¶61,108.)

And so the biggest concern for Comverge, as it has expressed in comments filed with FERC, “is that there is no clarity around the definition of reasonable expectation, and no parameters around what would justify a change of expectation.”

As Comverge sees it, the only documentation that would appear to satisfy the new proposed tariff “is an actual contract with a customer for the delivery year.”

The company fears that PJM’s new tariff aims to “walk back DR participation in the face of clamor from stakeholders … because it delivers capacity to PJM too cheaply, too reasonably, and too efficiently for their liking.”

Rapid changes in electric power markets are posing real-time challenges for operators of generating facilities across the country. Green energy mandates are driving expansion of variable generation. Shale gas reserves have pushed fuel and electricity prices to historic lows, just as new environmental rules are putting pressure on fossil-fired plants. Baseload facilities, designed to operate virtually 24/7, now are cycling to accommodate market fluctuations. And distributed generation, storage, and demand-side management are changing the way electricity is sold and distributed. 

Last fall, with the support of exclusive sponsor Invensys, we launched a new online publication to focus on this range of issues, specifically as they pertain to the generation side of the business. In Fortnightly’s Power Profit we present the perspectives of leaders in the field about trends in asset optimization, resource planning, and risk management. Last October in Washington, D.C., we convened a roundtable meeting – comprised of senior operations executives at a range of power companies – to address these topics as a group. Additionally, Federal Energy Regulatory Commissioner Tony Clark dropped in to deliver the keynote address (see sidebar “Jurisdiction Junction: FERC’s Tony Clark”). 

During the Fortnightly’s Power Profit executive roundtable, participants discussed the challenges of running long-term assets in a real-time world – and several agreed to let Fortnightly report some of their comments. They include:

• Paul G. Afonso, Partner, Brown Rudnick, and Executive Director, New England Energy Alliance;

• Jacob A. (Lon) Bouknight Jr., Executive Vice President and General Counsel, Public Service Enterprise Group;

• David A. Christian, Executive Vice President, Dominion Resources, and CEO, Dominion Generation Group;

• Hector Puente, Senior Vice President and COO, El Paso Electric;

• Thomas M. Rainwater, President and CEO, Essential Power; and

• Peter Martin, Vice President, Invensys Software and Industrial Automation, and Fellow, International Society of Automation.

Transition Planning

Michael Burr, Fortnightly: The power industry is going through some fundamental transitions, but it’s still uncertain which changes will prevail and what will result. If you had a crystal ball that could show you what the U.S. power market will look like in 10 years, how do you think that view would differ from today’s market?

Tom Rainwater, Essential Power: I’m hearing a growing concern from some within our industry and particularly from new entrants that the traditional model enjoyed in this industry is in jeopardy of becoming technologically obsolete. There are parallels to other industries such as computing. In our country we’ve migrated from mainframes to micro computing. We abandoned the central-office landline telephone model for a distributed mobile telecom model, and in emerging economies they’ve completely leapfrogged the landline telephony model and gone straight to mobile smart phones and mobile computing. Our smartphones are more powerful today in many instances than mainframes were a few years ago. Is it possible that distributed generation ultimately could leapfrog the business model of central generation, transmission, and distribution? Is this unlikely or a fundamental risk that we as executives in this industry need to confront?

Hector Puente, El Paso Electric: Thirty years ago, some people were predicting that cogeneration would take over our business. Many customers who installed cogeneration couldn’t keep it going. They learned it was high maintenance, and they went back to being traditional customers. Distributed generation could follow a similar pattern. Customers might see renewable generation systems degrade every year, in terms of output, and if rates don’t accurately reflect the cost of backing up renewables, we could have the problem of taking from the poor to subsidize the more affluent customers who can afford renewable sources.

These are real issues, but the more we raise them, the more people seem to think we’re hiding something or trying to control the market. 

The other real issue is the impact of distributed generation to system reliability. When there are rolling blackouts, utilities are blamed. The regulator doesn’t go to the DG-owning customer and say, ‘Why were you off grid?’

We need to hold policymakers’ feet to the fire. We either need a national energy policy, or we need the ability to take care of our customers’ needs with the most cost-effective and reliable sources of power. If we are going to have an energy policy, it should include solar, wind, nuclear, and also coal, because we have a lot of it.

Afonso: The pendulum is swinging again, and actions taken today will affect us four or five years from now. How do you place a value on things like environmental benefits and economic development? New England is coming to the point of saying ‘no’ to any fossil fuel, including natural gas, on the assumption that renewables will be sufficient to meet our energy and reliability needs. But everything is a choice and everything has a cost. If it’s windmills, then you have to build a transmission line. 

If you’re a regulator or elected official, you must have the courage to take a long-term view – balancing reliability and renewable policies and taking a more integrated point of view – even if it comes with a short-term political hit. 

We’ve seen long-term contract decisions coming out of Maryland and New Jersey [driven by state agencies]. Could contracts like that be used for renewables and be subject to the same legal attacks regarding long-term contracts?

Lon Bouknight, PSEG: It’s important to keep PURPA in mind when talking about renewables. PURPA [the Public Utility Regulatory Policies Act] is a statutory exception to the Federal Power Act. It delegates authority from the states to the federal government. That might involve different rules.

Gas Reliance

David Christian, Dominion: In 10 years the U.S. will be much more dependent on natural gas. EPA’s 316(b) and new source review (NSR) regulations could drive off an additional 20 to 30 GW of coal or nuclear. After the Kemper and Edwardsport projects, there will likely be no more new coal in the United States. Will the other markets for new natural gas capacity materialize? Will the re-industrialization of the U.S. really occur like some people say it will [because of low-cost natural gas], with new chemical and plastics plants in Ohio and in the Gulf region? It’s not clear to me they will jump in. They might wait to see how the electricity situation, with substantial new inelastic natural gas demand, plays out.

Perceived climate change risk is driving policy direction. Unfortunately over-reliance on gas also brings risks, in terms of price volatility and potential supply interruptions. Electricity prices going up isn’t seen as an important risk.

Puente: As an industry, we’re very fragmented, and we’re dealing with the same federal regulations and, in many cases, with the same state regulators. We need more of a common front to deal with regulatory issues.

Rainwater: Unfortunately the gas pipeline infrastructure hasn’t kept pace with the build-out of gas-fired power generation in several regions. For example, the existing infrastructure in New England is inadequate to support both power generation and also space heating needs during the cold winter peak heating season, and it’s strained even during summer periods now. It’s fundamentally different to have a gas-fired power plant in New England that relies on regional gas supplies with limited deliverability [compared to] a mine-mouth coal-fired power plant where the supply is local and adequate and we ship the power over long distances via the electric transmission system. 

[Also] I wonder if the growing dependence on IT infrastructure that’s at the core of our industry, where every major piece of equipment has an IP address, exposes us to unintended vulnerabilities. As well, the cost to remain current and avoid technological obsolescence from IT equipment is [rising] rapidly, and I wonder if this influence of IT in our sector could make the industry more vulnerable or fragile rather than more robust? 

I have a growing concern about the fragility of the power grid over the next five years or so in some areas. And I worry that some kind of watershed event could occur – a regional brownout or blackout and the ensuing public outcry – and regrettably the local distribution company will likely get the brunt of the criticism.

New Moon Shot

Puente: Making it all more difficult to manage is the fact that load isn’t growing. Few utilities are fortunate to have sustained growth, but if you aren’t growing, then you have to retire old plants, build new ones, remediate sites, build new transmission lines, and invest in smart grid systems etc., you keep piling costs onto a non-growing base. 

Christian: In some ways we’re the victims of our own success. Electricity prices have been driven down so low, and reliability has remained relatively high. 

Afonso: Public opinion drives public policy, and right now the public in the Northeast wants out of coal and isn't swayed by the possibility of reliability issues and resulting outages. 

Peter Martin, Invensys: Public opinion to a certain extent is driven by emotion. The public has little time for rationalizing. Can the power industry help in some way by making clearer the risks and the effects that can result if policymakers continue down the current path?

Rainwater: I wonder if we need something in our country analogous to [Pres. John F.] Kennedy’s challenge to land a man on the moon within a decade to spur development of a comprehensive, longer-term national energy policy that achieves, for example, energy independence within a decade. While it will be difficult it could be what it takes to galvanize various industries and move public opinion forward. 

There’s a role for nuclear power and for scrubbed baseload coal generation in our country. There’s also a role for gas-fired generation, for solar, wind, hydro and other renewable technologies. And there’s a role for energy efficiency and demand response. In other words, we need a portfolio approach to our energy challenges and also we need a thoughtful long-term energy, economics, and environmental policy in our country. To develop such a comprehensive systems view will take courage and conviction and regrettably there doesn’t seem to be a lot of courage in this city [D.C.] to tackle such major policy challenges. I worry about this not only as an energy executive but also as a global citizen.

Looking at Blue Sky

Christian: What is your view on microgrids? 

Rainwater: The military might need to be able to isolate from the grid and have self-sustained power generation to provide enhanced national security. I wonder if over the longer term this focus could shift to other industries as well, and if this trend will take hold over the next 10 to 15 years and fundamentally alter our business model.

Burr: I’ve been doing a lot of work related to microgrids lately. One key point that’s becoming clearer is that a microgrid isn’t just one thing. Rather it’s whatever the customer needs it to be. Some customers need microgrids for energy assurance – resilient and reliable backup power supplies – and for others, mainly in developing countries, it’s a matter of access to electricity, period. In some places microgrids are a tool for optimizing the use of renewable energy to displace expensive diesel generation. There isn’t just one definition of ‘microgrid,’ because a microgrid can be a whole range of things to suit different needs and situations.

Another point is that microgrids will become more cost-effective, for a broader range of customers, as various technologies mature. Fuel cells, for example, are nearing grid parity faster than I ever would have expected. (See “Embracing Disruption: Developing a leadership role for utilities in alternative technologies”). Advances in software, microgrid control systems, and storage, all improve microgrid economics.

Martin: What we’re seeing in the electric power industry is happening in every industry, except slower. The real-time nature of managing electric power is increasing quickly. Electricity distribution is becoming more like information distribution. 

Burr: What opportunities are arising from the changes that are happening in the industry? What do these changes mean for investment strategies?

Rainwater: A ‘blue sky’ approach to development of strategy might be a hard sell to a board of directors who perceive it as too risky. Instead, there might well be a tendency to adopt more of an incremental approach to investments.

Afonso: Utilities need to be concerned about disintermediating trends. Customers use iPhones and products coming out of Silicon Valley, so they are receptive to new technologies. The sales cycle is different from what utilities are accustomed to, and capital needs are different. But scalability is key, and utilities can be an important partner at that table. Utilities can influence what customers really need. There’s a great opportunity there.

Puente: There’s a difference between wanting to grow your business and wanting to survive. You don’t want to jump out of the business you’re in and try something totally different. Some companies have tried it and lost their shirts.

Christian: The industry needs leaders capable of operating in a VUCA environment (volatility, uncertainty, complexity, and ambiguity). The need for this kind of leadership is a strategic issue.

Mind the Pendulum

Burr: Edison Electric Institute is talking about trying to bolster the perceived value of reliable electricity service. People don’t understand what it takes to deliver reliable electricity, and therefore they don’t properly value it. Will educating customers cause them to ascribe higher value to electricity, and therefore be willing to accept cost increases to pay for grid modernization and generation upgrades? Amid all this uncertainty and the drivers in the market, are we heading toward a future where reliability is a premium product that customers must pay for separately?

Bouknight: If that happens, then it becomes a contest between the haves and have-nots. 

Puente: Reliability is a very subjective term. We can have the highest reliability numbers ever, and some customers will say we’re failing. Different parts of the country have different levels of reliability. If you live in the city, then you have multiple lines serving your home or business. Outside the city, you might only have one line.

Also telecommuting creates commercial load in residential areas. You’re now dealing with a lot of business customers in the residential neighborhood.

Christian: Some people pay extra for reliability already. Data centers have, in the past, requested redundant transmission-level service. 

Afonso: Reliability affects business, and that affects local economies and politics. The CEO of a pharmaceutical company called me one evening and explained that outages were causing quality problems and major costs when product runs were lost. He said if he couldn’t get the problem resolved he would leave the state and take 320 jobs with him. In the big scheme of things, 320 jobs doesn’t sound like much, but in a local community that is a major economic blow. 

Reliability also has bigger political ramifications. In 2004 leaders in the State of Massachusetts were talking about the interdependence of gas and electricity, and what it could mean for reliability especially during a cold snap. Here we are in 2013 and this remains an important issue that still needs to be resolved.

Christian: It’s getting worse. This is why NERC and most of the ISOs are taking a fresh look at the importance of fuel diversity as it relates to long-term reliability of electric service.

Afonso: Part of the problem is that some environmental advocates are purists. The impacts of environmental policies must be of concern to all policymakers. The industry needs to continue to influence lawmakers – and to provide air cover when they step up. There are a lot of knee-jerk reactions that happen in politics, and we need to make sure some people at regulatory agencies can bring a reality check to the decisions that are being taken. Eventually the pendulum is coming back.

Generation

Duke Energy Renewables installed three solar power facilities totaling 30 MW in Eastern North Carolina. The 20-MW Dogwood Solar Power Project is located in Halifax County, near Scotland Neck. The company is also building two 5-MW projects: the Windsor Cooper Hill project in Bertie County, near Windsor; and the Bethel Price project in Pitt County, near Bethel. Power from these projects will be sold through long-term, fixed-price contracts. SunEnergy1 built the PV projects, and expected to complete them at the end of 2013. ReneSola supplied PV modules for the three sites. 

Dynamic Energy Solutions began construction on a 904-kW roof-mounted solar array for DiCarloDistributors in Holtsville, N.Y. The company says the project will be one of the largest roof-mounted solar arrays in Long Island and will participate in the LIPA Clean Solar Initiative Feed-In-Tariff (FIT) program. Dynamic Energy will provide full turnkey services, including engineering, procurement and construction. 

Washington Gas Energy Systems signed a contract with Tucson Electric Power (TEP) to build, own and operate a 1-MW Cogenra Solar array that will provide renewable energy to the utility in Tucson, Ariz. The installation, awarded through a previous TEP RFP process, will consist of ground-mounted Cogenra T14 systems and will be constructed within the University of Arizona’s Science & Technology Park. TEP will purchase output under a 20-year contract. The project is expected to be completed in April 2014. 

Siemens received an order for two German offshore wind power plants to supply 97 wind turbines, each with a rating of 6 MW and a rotor diameter of 154 meters, to the Danish energy provider DONG Energy. The Gode Wind 1 (252 MW) and Gode Wind 2 (330 MW) plants will be erected off the North Sea island of Juist. This will mark the first time that Siemens will be supplying its new 6-MW wind turbines for offshore in Germany. Siemens will also service the wind turbines for a period of five years. Construction is planned to begin in the first half of 2015, with commissioning scheduled for the second half of 2016. 

FirstEnergy’s Metropolitan Edison (Met-Ed), Pennsylvania Electric (Penelec), PennsylvaniaPower (Penn Power), and West Penn Power utility operating companies have filed plans with the Pennsylvania Public Utility Commission (PPUC) to procure electric generation supply beginning June 2015 for customers who choose not to shop with alternate suppliers. The procurement process will be managed by CRA International, which will conduct auctions on a quarterly basis beginning October 2014, with generation prices calculated based on a blended average by customers’ class. The proposed program also includes a process for meeting state-mandated alternative energy standards, including a separate bidding process in order to meet a portion of the solar energy requirements through a request for proposal for 2-year contracts for the purchase of solar renewable energy credits. 

SunEdison secured $185 million (R1.8 billion) in foreign debt funding from the Overseas Private Investment Corporation (OPIC). This amounts to 75 percent of the project cost for the Boshof Solar Park Project (Boshof), located in South Africa’s Free State province near Kimberley. The plant will feed its 60-MW output into the South African grid, under the terms of a 20-year power purchase and implementation agreement with national power utility Eskom and the Department of Energy. Startup is scheduled for the fourth quarter of 2014. SunEdison will maintain a 51 percent ownership stake in the project, with South African companies holding the remaining 49 percent. 

GE signed a nearly $700 million contract with Saudi Electricity Company (SEC) to bring additional F-class combined-cycle gas turbines and associated equipment and services to the Kingdom of Saudi Arabia. GE says its technology will support SEC’s large, combined-cycle power plants to generate more than 3.8 GW of power and will provide fuel savings and lower emissions. The installations will include 12 GE 7F-5 gas turbines, four GE steam turbines, and 16 generators. The contract also includes two contractual service agreements, one for each site, covering planned maintenance on the units for eight years. 

Emerson Process Management plans to install its Ovation control system at two 1,050-MW coal-fired generating units under construction at the Taean plant in South Korea. Ovation technology will be installed at five of South Korea’s six largest coal-fired power plants. The $11 million contract was awarded by Daelim Industrial Co, one of South Korea’s largest construction firms, with startup expected in 2016. 

Global Trade &Development Consulting Group together with its project development partner, Energy Ventures, both Maryland-based companies, have been awarded a contract by the Ethiopian Ministry of Water and Energy and the board of directors of the Ethiopian Electric Power Corp. (EEPCo) to build, operate, and transfer three, 100-MW solar sites, in the eastern region of Ethiopia. Site selection, due diligence, and feasibility study were completed earlier this year, receiving both technical and financial approval from both the Ministry of Water and Energy and EEPCo.

M&A

Mainstream Renewable Power agreed to sell its 46-MW Oldman 2 wind farm under construction in Alberta, Canada, to IKEA. The $85 million (C$90 million) project is expected to be operational in the autumn of 2014, at which point IKEA take ownership. As part of the deal Mainstream will operate and maintain the wind farm for its lifespan. The project will be wholly owned by IKEA Canada. 

Allete Clean Energy signed an acquisition agreement to purchase wind farms in Minnesota, Iowa, and Oregon from AES Corp. in early 2014, plus an option to acquire a fourth wind energy facility in Pennsylvania in mid-2015. Allete Clean Energy would pay $27 million to acquire AES’s stake in operating wind energy projects in Lake Benton, Minn., Storm Lake, Ia., and Condon, Ore., with a total output of 231 MW, with an option to acquire its stake in the 101-MW Armenia Mountain, Penn., wind farm. All four projects sell their output under long-term contracts. The deal is expected to close in early 2014. 

Alterra amended its PPA for the 62-MW Jimmie Creek run-of-river hydroelectric project. Under the agreement, the Jimmie Creek project will sell 100 percent of its power to BC Hydro for 40 years commencing in August 2016. Alterra also agreed to purchase the 49 percent project stake held by an affiliate of General Electric Energy Financial Services, making Alterra the 100-percent owner. Alterra says the project has secured all first nations agreements and environmental permits. 

Southern Company and Turner Renewable Energy agreed to acquire the company’s second solar PV installation in California – the 20-MW Adobe project, on a 160-acre site in Kern County, Calif. The deal is expected to close upon the successful completion of construction, expected in spring 2014. The project will be built, operated, and maintained by SunEdison. Construction began in the fall of 2013.  Southern California Edison will buy the output under a 20-year contract.

Distributed Energy Resources

Maui Electric selected Greenlots and its SKY network EV management system for the first open access public charging station on Maui. A DC fast charger, supplied by ABB, will be installed at Maui Electric’s Kahului offices by the end of the year and will be operational and ready for public use by the first quarter of 2014. DC chargers running on SKY allow drivers to charge their cars, free from subscription-based issues, and offer payment options for credit cards via mobile apps, RFID cards, pay-by-phone, or card swipe.

The U.S. Army Corps of Engineers Engineering and Support Center in Huntsville, Ala., contracted Eaton to implement alternative energy and conservation projects at U.S. Army-operated facilities around the world. Eaton is one of 11 companies to receive the $600 million shared capacity multiple award task order contract. Under the contract, Eaton will provide existing condition surveys, system designs, installation, and commissioning for energy efficiency and renewable energy projects. Planned projects include, but are not limited to, the implementation of solar and wind generation, geothermal heating, lighting retrofits, and energy monitoring and control systems. The services entail a project scope of one base year, with four optional years to include all design and construction work.

Natural Gas

The Federal Energy Regulatory Commission approved construction of Columbia Gas Transmission’s Line MB Extension natural gas system modernization project in Baltimore and Harford Counties in Maryland. The certificate of public convenience and necessity instructs Columbia to move forward with the 21.3-mile pipeline and begin construction in 2014. The project is designed to improve interstate natural gas service reliability for local utilities that serve residents and businesses in central Maryland and surrounding regions. It’s also designed to reduce system vulnerability to pipeline outages and to better facilitate pipeline safety inspections without disrupting natural gas service. Construction is scheduled to begin in 2014, with completion in 2015. 

Federal Energy Regulatory Commission (FERC) approved a plan by Williams Partners to expand the Transco natural gas pipeline system to provide service to a new, gas-fired, power-generation plant in Virginia. The $300 million Transco Virginia Southside Expansion is designed to provide 270,000 dekatherms per day of incremental transportation capacity in Virginia and North Carolina by September 2015. Of the total expanded capacity, more than 90 percent will serve Dominion Virginia Power’s new power plant; the remainder will serve Piedmont Natural Gas’s local distribution business in North Carolina. The expansion is part of $2.2 billion of Transco growth projects that Williams Partners said it plans to bring into service through 2017. 

Kalmbach Feeds and TruStar Energy commissioned a new compressed natural gas (CNG) public fueling station. The station, designed and constructed by TruStar Energy, is located in Upper Sandusky, Ohio, near the company’s Wyandot County manufacturing plants and distribution center. The station is part of a new venture, KalmbachClean Fuels, and will support Kalmbach’s new CNG-powered feed distribution trucks.

Metering

CPS Energy contracted Landis+Gyr to supply advanced residential electric meters for the utility’s grid modernization project. Landis+Gyr will provide 700,000 E-350 FOCUS advanced meters with shipments beginning early in 2014. The rollout is anticipated to take four years. In addition to metering technology, Landis+Gyr is operating a direct load control program at CPS Energy that has the potential to reduce 250 MW of peak demand. The utility is using virtual peak plant software and load control devices from Landis+Gyr to verify and measure energy savings from conservation events. 

AEP Ohio named Apex CoVantage as the installation partner for its system-wide automated meter reading (AMR) technology deployment. AEP Ohio will use ProField, Apex’s ERP system, for mobile workforce management. AEP Ohio is introducing AMR meters to increase reading percentages and enhance data security. 

Transmission

Entergy and ITC Holdings canceled their planned deal to spin off Entergy’s electric transmission business into a subsidiary of ITC. The companies reached the decision one day after the Mississippi Public Service Commission ruled that the deal wouldn’t be in the public interest. 

The California Independent System Operator (ISO) chose Pacific Gas and Electric (PG&E), MidAmerican Transmission,and Citizens Energy to develop, own, and operate a new transmission line in the Central Valley region of California. The 230- kV line will span about 70 miles across Fresno, Madera, and Kings counties, running from the Gates to Gregg substations, which are owned and operated by PG&E. The transmission line would be operational no later than 2022, and could come on line earlier. The project is subject to approval by the California Public Utilities Commission.

People

ProEnergy named Charlie Athanasia as its COO and Craig Kingsley as its v.p. of turbine services. Athanasia was v.p. of Alstom’s thermal services business in North America. Kingsley previously held positions at Dresser-Rand and other companies.

Entergy and ITC Holdings mutually agreed to end their pursuit of a spin/merger of Entergy's transmission business with ITC. The companies formally terminated the merger agreement and filed pleadings to withdraw the remaining transaction approval applications with Entergy's retail regulators, as well as the Missouri Public Service Commission and the Federal EnergyRegulatory Commission. The companies originally announced the deal on Dec. 5, 2011, and have spent the past two years working to obtain the necessary approvals to complete the transaction. The agreement called for Entergy to spin off its electric transmission business to a newly formed entity and merge it with a subsidiary of ITC.

Recently we witnessed history being made, but we don't know exactly when it happened.

It was January, certainly. Maybe the 10th, or maybe a day earlier.

That's when the Southwest Power Pool, in one of the most brazen moves yet seen in the power industry, dropped a single invoice in the mail: an invoice accompanied by a letter from its Chief Operating Officer Carl Monroe that, while perfectly cordial in tone ("Dear Richard," it begins), was sent nevertheless without a date affixed to it.

Was it the excitement of the moment? Very likely so, as this invoice surely marks a turning point for the power industry.

For it purports to bill MISO, the Midcontinent Independent System Operator, for some $2.4 million (including $1 million in penalties) that SPP claims are due and owing for the last two weeks of 2013, as compensation for uninvited, rogue power flows that it says MISO has loosed upon the SPP regional grid, as a consequence of Entergy's integration into the MISO footprint on December 19. Specifically, the six Entergy operating utilities - which SPP itself had once courted as potential members, before it was spurned - joined MISO and thereby formed what is now the nation's largest regional transmission organization, stretching from Manitoba all the way south to the Gulf of Mexico.

Welcome to the age of RTO competition: region vs. region, grid vs. grid. It could well outdo the choice wars between retail energy suppliers that we thought were in our future.

On January 30, in a second and separate invoice, SPP demanded another $6.9 million, covering that month's charges. No doubt we'll see more.

To understand the full intensity of this fight, let's turn to the parties themselves. Listen first to SPP, impugning MISO's daring reliance on its pitifully weak 1,000-MW physical tie to the Entergy system to achieve a market dispatch to serve Entergy's 27,000 MW of load - a gambit that SPP argues was known all along to be impossible, without the availability of additional physical transmission paths over SPP's lines, to catch and funnel the overflow:

"MISO's free, unlimited use of SPP's transmission system to serve the vast incremental load of the Entergy operating companies can no longer be found just, reasonable, and not unduly discriminatory... It makes no sense for all of the other users ... to have to pick up the tab."(Complaint of Southwest Power Pool, pp. 6-7, FERC Dkt. EL14-21, filed Jan. 28, 2014.)

But now comes MISO, which, while not denying the existence of Entergy-bound power flows spreading across neighboring grids, has nevertheless rejected all attempts to bill for these affronts as ultra vires: unsupported in law or regulation, either by SPP's open-access transmission tariff (OATT), or by the Joint Operating Agreement (JOA) signed between the two RTOs, which was approved by the Federal Energy Regulatory Commission back in 2005. MISO says the JOA grants it a right to share SPP line capacity to complete its market dispatch of resources to the Entergy companies, as long as that sharing doesn't threaten SPP's reliability or firm schedules.

Listen, if you will, to MISO's reply to the SPP complaint:

"Now that the integration [of Entergy] has been successful, SPP seeks to charge MISO for point-to-point transmission service and unreserved use on the SPP transmission system ... even though there is no provision in the SPP Tariff or the JOA that permits such a charge.

"SPP is seeking to extract dollars from MISO customers to enrich its transmission owners."(Answer of MISO, pp. 3-4, FERC Dkt. EL14-21, filed Feb. 18, 2014.)

But what of those caught in the middle?

Xcel Energy, which owns utility subsidiaries in both RTOs (Southwestern Public Service, in SPP, and Northern States Power, in MISO), rose quickly to the latter's defense:

"SPP variously characterizes the MISO market flows at issue as 'unfettered,' unilateral' or 'unlimited'... These assertions do not appear to be grounded in the facts."

TVA and the Southern Company, though not members of SPP, nevertheless fear that their grids, too, could become unintended hosts of MISO's power overflows. If compensation is due, they argue, it should be paid on unauthorized power overflows across all neighboring systems, and not just the SPP lines. (Comments of the Joint Parties, p. 7, FERC Dkt. EL14-21 & ER14-1174, filed Feb. 18, 2014.)

But Basin Electric Power Co-op., an SPP member, says it fully supports SPP's position that "it is simply wrong, contractually or otherwise, to grant MISO what essential amounts to a free ride on neighboring transmission systems."

FERC had ruled for MISO in 2011 (136 FERC ¶61,010), interpreting JOA sec. 5.2 as granting permission to MISO to share the use of SPP lines to support the Entergy deal, and had denied rehearing in 2012 (138 FERC ¶61,055). Then late last year (on December 3), the D.C. Circuit vacated FERC's ruling (736 F.3d 994). But in sending the case back to FERC to better explain how it arrived at its findings, the court itself expressed no opinion on the merits. That left the opposing parties as they were, in their original positions, before the appellate court had acted. MISO cites that fact as cause for FERC now to reject SPP's tendered invoices. Yet that confidence rests on tender hooks.

On February 18, in a factsheet provided to the energy trade press and others interested in the case, MISO provided a summary of its positions on issues raised in SPP's complaint, plus an overview of a dozen or more "frequently asked questions" in Q&A format. Yet this effort only highlighted the fragility of MISO's position:

"Question 9: How will this cost be recovered if FERC sides with SPP?

"Answer: If FERC indicates it will rule in favor of SPP's interpretation, MISO will engage its stakeholders.

"Question 10: But, aren't you taking a risk with you [sic] stakeholders' money?

"Answer: We understand that some stakeholders have concerns about SPP's unauthorized bills to MISO and SPP's complaint against us. We take those concerns seriously."

Islands and Paths

This case turns on a single sentence in Section 5.2 of the MISO-SPP JOA: "If the Parties have contract paths to the same entity, the combined contract path capacity will be made available for use by both Parties."

As applied here, the "parties" are MISO and SPP. The "same entity" is Entergy, now a MISO member. SPP says this section authorizes either RTO to share in the use of the other's line capacity only as needed to reach "external third parties" - and not so that one RTO, in this case MISO, can use that appropriated capacity to serve its own load, Entergy.

SPP's Monroe highlights that fact his affidavit filed January 28 with SPP's complaint:

"I recall internal discussions at SPP about the language of section 5.2 ... [We] understood that 'contract paths' from MISO and SPP 'to other entities' was intended to describe the ability of either party to conduct point-to-point transmission transactions to and from third-party systems that were not a part of either MISO or SPP...

"We certainly had no idea that MISO ... would later claim that the provision could serve as the basis of allowing ... unreserved use of SPP's transmission capacity to operate a market including both MISO's existing system and a large new member like Entergy."

Yet, as MISO argues, either party's internal discussions shouldn't carry much weight in arriving at the correct interpretation of sec. 5.2. Of like mind is the Louisiana Public Service Commission. Siding with MISO, the PSC has protested the SPP complaint:

"SPP's beliefs are of little or no assistance if those beliefs are wrong.

"SPP does not allege that it communicated its understanding of the contract path language with MISO until this current dispute arose long after the JOA was negotiated, signed, and approved."(Protest of La.PSC, p. 5, filed Feb. 18, 2014.)

The Louisiana commission also has been working hard to try to capture benefits for its local ratepayers from Entergy's sign-up with MISO. As an example, in January, in direct response to Entergy's integration into MISO, the state commission reformulated its methods for calculating avoided-cost rates for PURPA cogeneration QFs so as to reflect zonal or (in some cases) nodal clearing prices in the new MISO day-ahead market. The PSC wants to discourage "put" sales to local Louisiana utilities bound by PURPA with a QF purchase obligation, and instead to price all those transactions in the competitive day-ahead auction. (See, La.PSC Order No. U-32628-A [corrected], issued Jan. 9, 2014.)

Much of the debate at FERC and at the appeals court focused on the words "contract path." In fact, the court of appeals vacated FERC's 2011 declaratory order on the meaning of sec. 5.2 partly because it found that FERC acted arbitrarily by refusing to entertain expert witness testimony on the general meaning that the power industry ascribes to the term "contract path."

SPP would define that term as "a designated path over which parties engage in point-to-point transmission service transactions," implying a scheduled interchange between different ("external") third-party balancing areas. SPP's definition thus would rule out MISO's market-based flows to Entergy, a MISO member, which would arise instantaneously in real time through a bid-based dispatch and encompass only a single transmission provider balancing area, denoting network service. As SPP argues, "network service has no identified contract path."

But MISO would have us go beyond dictionary definitions, to examine the regulatory history of why sec. 5.2 reads the way it does.

As MISO explains it, sec. 5.2 of the MISO-SPP JOA was drafted specifically to mimic a very similar provision in section 6.5 contained in the MISO-PJM JOA. According to MISO, FERC approved that provision in the MISO-PJM JOA to solve the problem of a partial "islanding" of MISO's Michigan and Wisconsin areas, which had become somewhat electrically isolated from the remainder of the then Midwest ISO after the erstwhile "Alliance" companies had sided with PJM, and after Commonwealth Edison had moved its Chicago-area grid to PJM's corner.

According to MISO, "the commission accepted the provision as proposed by the RTOs [MISO and PJM] and, in a subsequent order, confirmed the essential purpose of sec. 6.5 as ... "addressing the weak MISO contract path capacity between Wisconsin and Michigan and the rest of MISO."(Answer of MISO, p. 20, FERC Dkt. EL14-21, filed Feb. 18, 2014.)

In other words, the "weak MISO contract path capacity" [FERC's words] between Wisconsin and Michigan and the rest of MISO would be addressed, as FERC explained, "by the sharing of the RTOs' combined contract path capacity in the JOA ... which will allow Wisconsin and Michigan utilities to access the RTOs combined capability under the Midwest ISO tariff."(MISO Answer, quoting from FERC's 2004 decision, at 106 FERC ¶61,250, para. 63.)

This problem, concerning MISO's need to use PJM lines to reach partially islanded areas in Wisconsin and Michigan, seems directly analogous to MISO's present need to rely on SPP capacity to reach its almost-completely islanded Entergy territories.

According to MISO, FERC's 2004 order interpreting the JOA with PJM "is simply irreconcilable with the SPP's 'point-to-point' interpretation."

No Harm, No Foul

SPP vs. MISO raises multiple issues fundamental to the RTO world. For example, to underpin its demands for compensation, SPP has filed a new tariff with FERC, albeit unilateral, unsigned, and unexecuted as yet, containing a stated rate to be applied to these rogue MISO flows across the SPP grid. This new tariff is called the "MISO Service Agreement," and it's where the numbers on the invoices originated. SPP describes this new tariff as defining a rate for non-firm, point-to-point transmission service provided to MISO. (See, SPP Tariff Filing, FERC Dkt. ER14-1174, filed Jan. 28, 2014.)

But there's a problem. As MISO has pointed out, when FERC reformed its pro forma OATT in Order 890, it stated clearly that RTO's can't be transmission customers. Rather, they are intended to be co-equals: each a transmission provider, and each independent of markets.

Says MISO: "Never before was an RTO made a transmission customer of another RTO.

"Such an arrangement has profound negative implications for the future of these organizations."

Another issue concerns loop flows - the incidental, unintentional overflows onto parallel paths that are inevitable under the laws of physics.

MISO argues that FERC always intended that RTOs resolve loop flows amicably, through JOA negotiations. In fact, in FERC Order 1000, governing regional transmission planning, the commission said its policy on loop flows implores caution "against the hasty submittal of ... unilateral filings and prefers resolution of parallel path flow issues on a consensual, regional basis."

SPP counters, however, that these MISO power overflows can't be classified as incidental, since any engineer should know you can't serve 27,000 MW of load through a 1,000-MW pipe. Thus, in SPP's view, FERC's policy on loop flows shouldn't apply, meaning that its hasty submittal of unilateral filings is perfectly proper.

But now we must get technical, delving into the RTO world of cross-border congestion management, including RCFs, or "reciprocal coordinated flowgates." MISO explains, describing the RTO-to-RTO congestion management process (CMP) and its more advanced cousin, the ICP, or interregional coordination process:

"The use of RCFs under the JOA allows the parties to maximize transmission system utilization by permitting reciprocal use up until congestion occurs, with the parties then returning to their allocation based on historic use.

"Available shared contract path capacity is efficiently used under normal operating conditions, but can be 'turned back' when congestion requires flow reductions to ensure that the owner of the capacity is able to serve its firm loads."(See, MISO Answer, pp. 44-45, FERC Dkt. EL14-21, filed Feb. 18, 2014.)

In other words, no harm, no foul.

MISO maintains that the excess power flows it has placed on SPP's grid are simply making use of transmission capacity that's there for the taking, as the MISO flows won't be imposing any congestion on SPP's native load:

"If congestion develops on an SPP flowgate, MISO will reduce the impact of these flows ... if no congestion is present, these flows are tolerated in exchange for the benefits of networked interconnection.

"It is a quibble how the flows are described... SPP does not allege that it is unable to sell transmission service, or has experienced increased congestion ... suffered any other harm that would justify compensation or penalties."(MISO Answer, pp. 47-48, FERC Dkt. EL14-21, filed Feb. 18, 2004.)

And that's Xcel's take as well:

"There is no suggestion in this case that the flows at issue are firm schedules serving firm loads that 'bump' SPP's firm use of its own system."(Xcel comments, p. 8.)

But listen to the SPP transmission owners themselves, commenting on the dispute, who offer up some of the most remarkable prose ever found in a FERC proceeding:

"SPP's transmission system is not a fallow field awaiting planting from the first person willing to scatter some seeds."

Nosey Neighbors

Though it remains absolutely confident of the rightness of its cause, the Midcontinent ISO has taken the unusual step of answering SPP's complaint and invoices with a complaint of its own (MISO v. SPP, FERC Dkt. EL14-30, filed Feb. 18, 2014), in which it has warned that SPP's actions are "casting a financial cloud over the MISO markets."

That cloud concerns ORCA, the "Operations Reliability Coordination Agreement" proposed by MISO and OK'd by FERC last fall. Parties to the agreement include MISO, plus various neighboring utility systems other than SPP, known under ORCA as the "Joint Parties," that might also be affected by MISO's flows to Entergy, such as TVA and the Southern Company (See, Dkt. ER13-2162, Oct. 10, 2013, 145 FERC ¶61,032.)

MISO now claims that it has received three "nearly identical letters," from three of the ORCA signatories - TVA, LG&E-KU, and one very small utility, Associated Electric Co-op, Inc. (AECI), which has figured prominently in the Entergy integration.

AECI, which serves Missouri's "Boot Heel" district near earthquake-prone New Madrid, is the reason that MISO member Ameren maintains its 1,000-MW link to Entergy-Arkansas. According to MISO, in the letters the three utilities threaten to renege on their ORCA obligations to work with MISO to manage power flows to Entergy.

As MISO has explained, ORCA establishes an "operations transition period," during which time MISO will limit its directional market flows between the new MISO South Region (Entergy) and MISO Midwest, its prior historical footprint. North-to-South flows are defined as "negative"; South-to-North flows are "positive." OTP Phase 1 (ending April 2014) limits total net flows (positive minus negative) to 2,000 MW. Phases 2 and 3 retain that limit but add a few wrinkles, such as testing and validation of flow effects. But after OTP Phase 3 ends, on April 1, 2015, the 2,000-MW flow limit in ORCA falls away, allowing higher flows.

Nevertheless, those three nearly identical letters threaten to tear up the ORCA provisions. According to MISO, in spite of the ORCA limit of 2,000 MW, the letters from TVA, AECI, and LG&E-KU demand that MISO limit its region-to-region flows to 1,000 MW, the capacity of the physical tie. TVA's letter, in fact, says it "reserves the right to charge MISO for any use of unreserved capacity on the TVA transmission system if MISO transfers exceed the 1,000-MW contract path limitation."

To MISO's eyes, these three joint parties have now sided with SPP. They base their demand, says MISO, on the idea that the D.C. Circuit order settled the case in favor of Southwest Power Pool, rather than simply sending the issue back to FERC.

On January 29, in a presentation to the ORCA Reliability Subcommittee, MISO had acknowledged that recent extreme cold conditions in the Northeast had given rise to an "unusual level of Northeast imports," resulting in large parallel flows across the TVA system, which might limit its ambitions to increase south-north and north-south flows.

But barring that, MISO suggested in that same presentation that once the ORCA limit expires, there ought to be an additional 4,800 to 5,400 MW of additional transfer capability between MISO-Midwest and MISO-South, on top of flows that are occurring now in compliance with the Phase 1 ORCA limit of 2,000 MW.

In other words, by spring of next year, SPP could be looking at MISO dispatch flows between its Midwest and Entergy regions totaling seven times the capacity of the actual physical tie.

ISO New England wants to remake its forward capacity market. As it explains, the FCA falls short of what's really needed to ensure reliability, as the market pays winning bidders only according to their unit "availability," as defined under various technical rules riddled with holes, whereas, as the ISO contends, a better test of true capability would instead measure whether power plants and other resources are actually supplying energy in real time during conditions of scarcity.

The current availability metric, says the ISO, is "deeply flawed."

We've alluded to these complaints already in this column and elsewhere in Fortnightly. A year ago, ISO-NE confirmed that, in examining the dispatch response following the 36 largest electric system contingency events of the last several years, it found that, on average, the response rate for the region's non-hydro resources was less than 60 percent of what was requested. (See, "No Fuel, No Power," April 2013.)

Outage rates are rising. EFORd (equivalent forced outage rate - demand) rose in New England for fossil-fired steam units from about 4.25 percent in 2007 to about 16.5 percent in 2003, and climbed 2.33 times for all generators over the same period.

Capacity resources satisfy technical eligibility rules for participation in the FCM, but then tend to fail to perform adequately when called on during shortage events. And when the ISO then turns to lower-tier plants with capacity supply obligations, it often finds they will require long lead times to start and ramp up, and so are unable to address the reserve shortage in real time.

Testifying in support of the ISO, Peter Cramton, professor of economics at the University of Maryland, notable also for his testimony given at FERC's technical conference last September on the future of capacity markets, describes the problem as "money for nothing" - how some resources operate only to satisfy their annual capability audit (enough to get paid), but then contribute precious little resource adequacy.

Attorney Randall Speck (Kaye Scholer), who represents various New England regulators, consumer reps, and public advocates (all of which oppose the ISO's current effort to remake the FCA) favors a more colorful metaphor. He talks of "zombie" generators - units paid to be available but which are actually unable to perform.

The ISO puts it bluntly: "The system's operators no longer have confidence that resources will be able to perform when needed."

A Middle Ground?

The ISO calls its plan "Pay for Performance." It would set up a regime by which generators, resources, and other capacity suppliers are pitted against one another -their real-time performance during acute scarcity conditions would be compared, one against the other, to judge which resources are guilty of under-performing and which qualify as over-performers. Laggards would be penalized, while leaders get incentive rewards.

Nevertheless, the vote in favor of the ISO's PfP plan among market participants was only 10 percent. Compare that against the 80 percent that endorsed a rival and much less radical alternative put forth by the New England Power Pool Participants Committee (Nepool).

And much of that negative voting margin may well come from the ISO's proposed maximum penalty factor of $5,455 per MWh, which would come into play at the end of a multi-year phase-in period. This maximum potential penalty factor, which could be imposed on a generator regardless of fault - and depending upon the random and unforeseeable chance that the unit might be operating or not during any particular five-minute dispatch interval - is seen as imposing an unhedgeable risk. It will make informed and systematic capacity auction bidding virtually impossible, the critics say, for the typical resource.

Some welcome this prospect as consistent with other commodity futures markets, such attorney Daniel Galaburda, of National Grid:

"No exemptions for [non]performance... This is as it should be."

But most others warn of illogical and unwarranted sanctions:

"Even resources that 'perform' may find themselves penalized rather than 'paid,'" say attorneys Scott Strauss, Jeffrey Schwarz, and Lati Nurani (Spiegel & McDiarmid), representing some of New England's co-ops and muni utilities.

That's because you can be penalized severely even if your nonperformance is caused by a transmission outage, or because you could have gained approval ahead of time for a planned, scheduled maintenance outage, as per rule, so that your plant is offline (with the ISO's OK) during a five-minute dispatch interval when power reserves are scarce.

Strict liability. No exemptions. No recourse.

And remember, we're talking three years out. The most recent auction, FCA 8, (see more below), was conducted in February to ensure resource adequacy for the 12-month capability year beginning June 1, 2017.

But do not assume by the paltry 10-percent vote for PfP that the ISO's plan is now dead in the water. Rather, as Entergy Nuclear Power Marketing pointed out in answering comments submitted in late February, there appears to be a "middle ground" by which the Federal Energy Regulatory Commission (FERC) might find enough consensus among stakeholders to warrant approval. According to Entergy Nuclear, that consensus can be found in jettisoning the "no excuses,""be-there-or-else" aspect of the ISO's PfP plan.

This consensus, Entergy adds, comes from a "diverse group of state representatives, renewables, demand response (DR) providers, and generators," including ENPM, that have each "signaled" separately that the ISO's PfP idea could be "workable" if only it would include "reasonable" exemptions. (See, Answer of ENPM, FERC Dkts. ER14-1050-000, 1050-001, filed Feb. 27, 2014.)

But even that view might prove too optimistic. While the ISO's PfP plan might well boost plant availability and reliability during periods of shortage, and while the financial risks it creates for generators might prove more manageable if no-fault exemptions are permitted, the real question concerns what would happen to clearing prices in the forward capacity market: they could climb high enough to cancel out the energy price savings and reliability benefits.

A year ago in March, ISO New England retained Analysis Group to conduct a study to assess the effect of the PfP idea. Yet that study, completed and released last fall, now appears hopelessly out of date.

As we reported late last year, the Analysis Group study found that total annual FCM costs under the ISO's proposed new PfP plan would range only from $1.56 billion to $1.86 billion, depending on the assumed scenario regarding natural gas availability, representing an increase in total annual capacity market costs running anywhere from 25 to 49 percent. (Tranche Warfare, Fortnightly, Dec 2013, at p.33.) But that was before the ISO conducted its latest capacity market auction, FCA 8, on February 3.

In a press release issued two days later, the ISO reported that for the first time ever in capacity market history, the auction had failed to procure sufficient capacity to satisfy the region's installed capacity requirement, clearing only 33,700 MW out of 33,855 MW needed. Moreover, new resources (1,370 MW) had cleared at a price of $15/kW-month, far above the $3.76/kW-mo. that formed the starting point for assumptions in the Analysis Group study. Thus, the FCA 8 total capacity cost would be $3.05 billion - roughly three times the status quo FCM cost that formed the underpinnings of the study, and nearly double the study's prediction of FCA market costs predicted for the ISO's PfP plan, if it should be approved, under the study's moderate gas shortage scenario. (See, Joint Comments, p.7, Conn. Consumer Counsel, Maine Pub. Advocate, Mass. Atty. Gen., N.H. Consumer Advocate, FERC Dkt. ER14-1050-000, 001, filed Feb. 12, 2014.)

According to Gordon van Welie, president and CEO of ISO-NE, the culprit was the "large number of resource retirements - nearly 10 percent of the region's total capacity - announced in just the past few months [that had] caused a dramatic shift in the region's power supply landscape."

The announced retirements included: Brayton Point, Vermont Yankee, Salem Harbor, and Norwalk Harbor.

Opponents have jumped on these developments, suggesting the recent auction shows capacity suppliers already are running scared - fleeing the market ahead of the ISO's new performance incentives.

Attorney Randall Speck, representing the Connecticut Attorney General, PUC and the consumer counsel, along with the Rhode Island PUC, predicts that PfP could create a "false" shortage of capacity by encouraging resources to de-list (exit) from the FCM auctions, since PfP would assess no performance penalties on resources not vested with an FCA capacity service obligation (CSO), but yet would allow such non-CSO resources earn performance rewards all the same.

Speck adds that in 2012, in a white paper exploring the PfP idea, the ISO had conceded that "it is difficult to predict the effect on capacity market prices as a result of these changes."(Comments, pp. 26, 21, Conn. PURA et al., FERC Dkt. ER14-1050-000, 001, filed Feb. 12, 2014.)

Nepool asked Julia Frayer, partner and managing director of London Economics International, about her findings on the merits of the ISO's PfP plan. Her answer:

"The Analysis Group used the word 'ambiguous' when describing potential outcomes, and I would agree."

Probabilistic vs. Operational

Here's a useful way to think about what ISO New England is trying to do. It comes from Dominion Resources, from comments (p.23) that Dominion filed at FERC on Feb. 12, opposing the PfP Plan, and endorsing instead the Nepool alternative:

"The Pay for Performance proposal extracts appropriate and needed energy scarcity pricing from the real-time energy markets and embeds them in the capacity product."

In other words, the ISO's PfP Plan would propose in theory to do something no other RTO is doing, and exactly the opposite of what the experts recommended to FERC last September at the commission's technical conference on capacity markets as they now exist in the eastern regional transmission organizations.

Recall that at that conference, commissioner Cheryl LaFleur had asked whether capacity markets should focus on differing operational characteristics, offering separate tranches for baseload, green, ramping capability, etc. And the preferred answer seemed to be decidedly "no."("Tranche Warfare," p.28, Fortnightly, Dec 2013, at pp. 29-30.)

Thereafter, in seeking to answer FERC's inquiries about whether RTOs should in fact attempt to add operational characteristics as an additional parameter in regional capacity markets, David Patton, ISO New England's external monitor, replied in his post-conference comments (See, Comments of Potomac Economics, pp. 7-8, FERC Dkt. AD13-7-000, filed Jan. 8, 2014) that RTOs should do so only if the characteristic in question is one that can't be reflected in the bidding and clearing of the energy or ancillary services (reserves) markets, and then he added, by the way:

"We are not currently aware of any such characteristics."

Many of the 80-percent cohort of New England market participants who have voted against the PfP concept point to just this idea - that it's wrong to add operational factors into the capacity market mix - as reason to reject the ISO's proposal. They argue that capacity is a probabilistic concept: capacity isn't a real concrete product, but rather, an abstract mathematical construct that can prove useful in estimating the amount of energy potential needed to assure resource adequacy.

For example, the current ISO-NE market rule defines ICR (the installed capacity requirement) such that "the probability of disconnecting non-interruptible customers due to resource deficiency, on the average, will be no more than once in 10 years. Compliance with this resource adequacy planning criterion shall be evaluated probabilistically."

Consultant Richard Tabors, formerly with Charles River, now with Greylock McKinnon Associates, describes how ISO New England uses grid topology software tools in what is essentially a probabilistic planning process to calculate a solution:

"The answer from GE-MARS is in terms of megawatts of capacity needed on a planning basis. The model results consider that operating procedures of ISO-NE will accommodate any reserve scarcity condition that does not result in actual loss of load. The results of GE-MARS does not, and from an analytic perspective cannot, be used to measure the need for operational capacity. The tool and logic to arrive can only be applied to measurement of need for planning capacity which is the product of the FCM."

Tabors, who supports the Nepool alternative proposal to PfP, thus concludes:

"I disagree that the forward capacity market is broken."

And this (comments, p. 6) from Entergy Nuclear: "Using the capacity market to reward or penalize ... performance in real time is not what capacity market have ever been designed to do."

Rather, that's the role of the energy market:

"If a resource is providing energy, it is paid. If it is not providing energy, it is not paid. If the energy market is failing to provide adequate incentives ... it should be reformed. The FCM ... is a long-term planning market, and it should remain so."

That's also the view (comments, p. 20) from Dominion:

"The real-time nature of energy and ancillary services markets provides the immediacy of price signals that will incent the operational characteristics desired by the market."

And from PSEG (comments, p. 4, filed Feb. 12, 2014):

"Utilizing the many proven design elements already being utilized by other RTOs and ISOs is the more appropriate, prudent and commercially palatable course to follow."

Winners and Losers

The prevailing view seems to be that New England's PfP Plan will favor low-cost baseload plants with higher capacity factors (a higher proportion of time during which the plant is actually running), plus fast-start peaking units that can operate within 10 to 30 minutes from a standing start. By contrast, the PfP is thought likely to penalize higher-cost fossil baseload (older coal and oil) and units with slower ramp times. The "winners" in the first two categories will more likely be running, or be able to start running, once there arises a condition of reserve scarcity, and thus will likely qualify under the PfP regime for an overperformance credit.

Exelon agrees, noting that higher-cost baseload plants (such as older coal units) will lose since most shortage events occur when the system is at a balancing ratio (current load as a proportion of the ICR) of 75 percent or less, when those higher-cost baseload plants are not in merit. (Comments of Exelon, et al., p. 27, filed Feb. 12, 2014.)

And Richard Tabors points out: "Assuming an 80 percent availability of the base load generator, it has a 4:1 greater chance of receiving a net positive payment than of facing a penalty."(Affidavit of Richard Tabors, p. 9, Nepool Alternative Proposed Market Rule, Attachment N-1f, FERC Dkt. ER14-1050-001, filed Jan. 17, 2014.)

Nevertheless, not everyone agrees.

Dominion says its Millstone nuke could be a big loser. For example, if the 1,155-MW unit 3 has cleared a bid to supply 1,000 MW of capacity, but finds itself offline for refueling when a capacity scarcity condition arises across a full hour (as defined, that would mean 12 consecutive five-minute dispatch intervals of scarcity), then, if the balancing ratio is 50 percent, the plant would end up paying a $2.7 million penalty: $5,455/MWh [the capacity performance penalty rate] x 500 [the plant's CSO times the balancing ratio] x 1 hour.

And that, says Dominion, would be "simply for refueling in accordance with prudent utility practice and the ISO's scheduling."

Could it happen? Dominion notes that its North Anna nuke was on a refueling outage Sept. 10 and 11, 2013, when temperatures in Baltimore hit 93 and 95 degrees - a situation that, during such a shoulder season, might well lead to scarcity.

Renewables, however, present an interesting case. Some seem to believe that intermittent wind and solar will come up losers, as they must depend on dumb luck whether the wind will be blowing or the sun shining at the exact moment that scarcity arises, and thus should be exempted from having to pay underperformance penalties. One such apologist is Brookfield Energy Marketing General Partner Aleksandar Mitreski, who argues nevertheless that wind and solar plants should remain eligible to receive rewards for overperformance.

But note: Renewable Energy New England and First Wind Energy say the complete opposite, suggesting that the term "intermittent" isn't properly understood by the industry at large. (See Comments, p. 6, filed Feb. 12, 2014.)

"Rather than intermittent, wind and solar resources are predictably variable. This predictable variability gives both resource owners and ISO-NE the ability to forecast and rely on performance from these resources.

"In the context of the capacity market, the ability to predict performance also gives renewable resource owners the ability to assess the risk of nonperformance during scarcity events."

Theory and Practice

Another interesting angle to New England's PfP Plan is how it dovetails with smart grid concepts such as dynamic pricing and price-responsive demand, the latter being linked also to what's known as VOLL pricing: the idea of a market price that reflects what a customer should be willing to pay to avoid an interruption.

In fact, it's VOLL pricing that leads the ISO to its $5,455/MWh penalty factor for capacity under- or over-performance. To calculate the penalty factor, the ISO estimates the cost of new entry (CONE) for new electric capacity, adds a risk premium for participation in the capacity market, and then divides that sum by the unit's expected actual performance across the expected number of hours of scarcity.

By this formula, the payment for capacity performance should equal $106,000/MW-yr, divided by the product of 0.92 (expected unit performance of 92 percent) times 21.2 hours (the number of hours per year of expected scarcity). The result equals $5,455/MWh.

Note here, however, that while he agrees with the theory, the ISO's external market monitor David Patton takes issue with the numbers.

According to Patton, the ISO's propose performance penalty factor of $5,455/MWh implies a VOLL price of $200,000/MWh - a figure Patton feels is much too high.

Instead, based on studies conducted by London Economics, SAIC, and the Brattle Group, Patton believes that the true VOLL price should fall somewhere between $20,000 and $30,000/MWh. Thus, Patton would reduce the ISO's proposed performance penalty factor from $5,455/MWh to a much less formidable $2,000/MWh. (See, Comments of ISO New England EMM, pp. 11-17, filed Feb. 13, 2014.)

Patton also favors a variable "sloped" or "stepped" performance factor to reflect the relative severity of a particular scarcity condition, and suggests that the ISO might temper its "no excuses" mandate by setting half the performance rate on traditional notions of availability, and half on a strict liability basis.

But then comes Maine attorney Donald Sipe (Preti Flaherty), counsel for the Industrial Energy Group, to bring us all back to earth, courtesy of this quote he takes from Albert Einstein:

"In theory, theory and practice are the same. In practice, they are not."

As Sipe explains, "one day in ten" is not an economic standard, but a "higher societal value" than what is implied by VOLL pricing.

"It may be true," he continues, "that in a famine, the poor eventually 'choose' not to buy bread when the price exceeds their resources.

"This is not a criticism of theory, only of its uncritical application."

The Federal Energy Regulatory Commission (FERC) approved the acquisition of UNS Energy by Fortis, finding the transaction is consistent with the public interest. The ruling is the next step toward finalizing the transaction. UNS Energy shareholders approved the acquisition on March 26, 2014. The closing of the acquisition of UNS Energy, which is expected to occur by the end of 2014, is subject to receipt of certain regulatory and government approvals, including approval by the Arizona Corporation Commission (ACC); review by the Committee on Foreign Investment in the United States; the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and the satisfaction of customary closing conditions.