The Old Drawing Board

One of the hardest jobs in the world is the state utility commissioner’s.

In one of my first Frontlines columns as Fortnightly’s editor, I focused on the regulator’s job (“Creating the Perfect Regulator,” November 2007). I proposed that the defining characteristics of the perfect regulator included omniscience, Solomonic wisdom, clairvoyance, and absolute righteousness.

Of course no mortal possesses those characteristics. No regulator can fully comprehend every single nuance shaping the future of electric and gas utility services, much less plan for every eventuality. But in some sense, PUCs in many states are expected to do just that—not alone, of course, but in collaboration with utilities, legislators, and stakeholder groups.

To bring greater clarity to utility planning and development, many states embarked on integrated resource planning (IRP) back in the 1980s. More than half of U.S. states pursued some form of IRP, most in response to two momentous events. First, the energy crisis of the 1970s turned the spotlight on oil as a risky fuel source. And second, the Three Mile Island accident raised safety concerns, and brought the decline of nuclear construction—plus billions of dollars in ratepayer-funded cost overruns. Both events highlighted the risks of over-reliance on any given energy resource, and drove regulators to intervene more directly in utility planning.

Many of these same forces are prompting states to consider whether today’s planning processes are up to the task. Except this time it’s not nuclear and oil raising worries; it’s coal and gas, along with a host of other uncertainties. The industry is, without question, more complicated today than it was in the 1980s—with organized regional markets creating a virtual third layer of grid regulation, sandwiched between FERC’s oversight and the states’ review; and with the crazy quilt of regulation even further complicated by demand-side initiatives and constantly shifting incentives and environmental rules. State regulators understandably might react to federal folderol by updating, refining, and strengthening the planning processes within their domain.

Back to the Future

As a regulatory phenomenon, IRP had its heyday in the 1980s and 1990s. Since then, the states that wanted to intervene in top-level planning either made it part of their general regulatory structure, or they tried it and gave it up for one reason or another.

In Missouri, for example, the Public Service Commission first enacted IRP rules in 1993, but later suspended them, in part because competitive wholesale markets seemed to obviate the need for top-down planning. Instead the commission conferred with utilities to ensure near-term resource adequacy, and left market forces to take care of the rest. In 2009, however, the commission picked up the IRP baton again, when it saw major changes in terms of customer load, demand-side resource capabilities, and environmental mandates. The PSC adopted new IRP rules in 2011 to set minimum standards for utilities’ resource planning processes. (See Missouri code, 4 CSR 240-22, May 31, 2011).

Arizona, similarly, put its IRP rules on hiatus in 1995. Then in 2005 the Arizona Corporation Commission (ACC) opened resource planning hearings in a rate case involving Arizona Public Service, and two years later conducted hearings related to energy procurement practices by utilities. Those hearings led the commission to reinstate its IRP rule in 2010—with substantive amendments, including requirements for utilities to consider a longer planning horizon (15 years instead of 10); incorporate demand-side and renewable resources in their plans; consider environmental factors; and demonstrate compliance with best procurement practices. (See Dkt. No. RE-00000A-09-0249, June 3, 2010).

In some other states, IRP processes have remained in effect, but now are being substantially updated or applied more rigorously. In one example, the Indiana Utility Regulatory Commission (IURC) is working to give the state’s IRP more teeth, requiring greater transparency and stakeholder input, consideration of demand-side programs, and perhaps most importantly, a provision that would mandate IURC’s formal determination that utilities’ plans are in compliance.

At least one state is implementing IRP for the first time. After five years of hearings, the Louisiana PSC earlier this year ordered all utilities in the state to file integrated resource plans, requiring evaluation of both supply and demand-side resources, plus transparency and stakeholder participation. The commission stresses that the IRP rules don’t “mandate a specific outcome,” but that the PSC will consider a utility’s IRP when determining prudence of investments in rate cases. (See LPSC Dkt. No. R-30021, Corrected General Order, March 21, 2012, See LPSC Dkt. No. R-30021, Corrected General Order, March 21, 2012).

Sharper Tools

These examples—and others on various PUC dockets—share at least one common thread, and that’s uncertainty about whether affordable supply resources will be available over the long-term. PUCs are concerned that a rapid shutdown of coal-fired plants will start a full-tilt dash to gas—similar to the one that caused bankruptcies among independent power producers in the late 1990s and early 2000s. But this time around, ratepayers and not IPP investors will be stuck with the risk, if utilities rush to add all that new gas-fired capacity to rate base. (See “Bill Hogan, Unbundled.”)

Further, state regulators seem less than 100-percent confident about wholesale markets’ ability to deliver resource adequacy without some planning by load-serving entities. As utilities spend billions of dollars on transmission lines—many of which will help generators access bigger markets—regulators are increasingly troubled about their limited role in interstate projects, which raise monthly bills for retail customers without necessarily producing bona fide resource security for those same customers.

At press time, the Midwest Independent Transmission System Operator (MISO) submitted to FERC its proposed changes to the MISO transmission owners’ agreement, giving state regulators a bigger seat at the planning table. Whether such moves will resolve state concerns about grid planning remains uncertain. Some states might decide to tweak their IRP rules to focus more attention on transmission plans and their rate effects—particularly given the changes wrought by FERC Order 1000, vis-à-vis cost-allocation methodologies and eliminating rights of first refusal.

What seems certain, however, is that resource planning isn’t getting any easier, and state regulators want to be sure that utilities’ plans are both financially prudent and consistent with state policy priorities—no matter what’s happening at federal and regional levels.

“With all these varying factors moving around and the states playing a major role in every one, I wouldn’t be surprised to see more emphasis on IRP,” says Sheila Hollis, a partner with Duane Morris who spoke to Fortnightly for this issue’s cover story (See “Federal Feud.”). “This is particularly true if political winds shift. So much about utility planning is politically driven, and there are so many layers of decision making.”

Sorting through such layers of complexity has never been easy. But in many states, IRP has given regulators a tool for checking utilities’ work and holding them accountable. It makes sense that some states now are refining that tool to accommodate today’s realities. That’s good news for regulators struggling to do the world’s toughest job.