Uncertainty Still Prevails, but Utilities Plan for Future

by Teresa Hansen, editor in chief

The U.S. economy continued its slow comeback in 2011 after most economists and financial experts declared the recession officially over in the second half of 2010. Uncertainty stemming from the turbulent global economy and geopolitical climate, however, is keeping utility executives and investors alike awake at night. Despite this economic uncertainty, many U.S. investor-owned utilities have assessed their risks and are moving ahead with long-term investment strategies.

“Any interruption in investment plans and activities in 2011 occurred during the summer discussion about increasing the U.S. debt ceiling and fear surrounding the U.S. credit downgrade by Standard & Poor’s,” said Tom Flaherty, a senior partner with Booz & Co. “This caused a little slowdown in activity as companies paused to see how the downgrade affected the markets and the cost of capital, but didn’t halt investment. In fact, the downgrade and debt ceiling activity didn’t trickle down much at all to the utility sector. The industry kept right on expanding and right on building.”

Electric Light & Power has turned to Booz & Co.’s energy practice experts each January for several years to get the lowdown on where utilities have been spending and where they’re likely to invest in the near future. This is the third year Flaherty has shared his insight.

“Utility management began to affirm strategic direction in late 2010 and the first quarter of 2011,” Flaherty said. “Strategy on future capital investment and mergers and acquisitions were planned and executed in the first half of 2011.”

Investment was up in 2011 and will continue to increase, he said. Capital spending projections for 2012-2013 are approaching $100 billion in each year. (See figure on Page 27.) And this expected investment in 2012 and 2013 could be understated because the breadth and cost of environmental compliance likely will be higher than planned. Recognizing that stricter environmental regulations were coming, a lot of utilities made decisions and announcements in 2011 about coal-fired plant retirements, with more expected soon.

Flaherty said utilities also will spend more on transmission infrastructure.

“These two areas will sustain or perhaps boost capital spending above the forecast,” he said.

Some utilities made investments in renewable energy in 2011 as well, trying to get in before the Section 1603 subsidy provisions disappeared.

Regulation Drives Capital Spending Decisions

As Flaherty predicted in 2010, lawmakers again did little in 2011 to clear utilities’ uncertain path forward. Last year he predicted the Environmental Protection Agency (EPA) would enact regulation and the only question was how aggressive the regulation would be. That question was answered in December when the EPA enacted two new regulations: the Cross-State Air Pollution Rule, which a federal court has temporarily blocked from implementation, and the Mercury and Air Toxics Standards (MATS). The regulations were implemented as the result of the 1990 Clean Air Act amendments.

The MATS rule requires power plants to reduce emissions of mercury, arsenic, chromium, nickel and acid gases—some of the dirtiest plants by as much as 90 percent—within the next three to four years. Plants that do not comply with the new standards will be forced to shut down.

“The first issue is whether these rules as proposed will turn out to be the same after negotiations and litigation,” he said.

Flaherty said the industry likely will have more time to comply with the rules than currently identified. And litigation likely will extend the compliance window.

“The broad direction of the EPA’s rules is apparent, but the time frame for compliance and the ultimate strictures for conforming will likely be relaxed,” Flaherty said.

He said all bets on implementing these rules are off if a change in the White House occurs.

“A change in the White House will dramatically impact the substance and viability of these rules,” he said. “Even if there is no change in the White House, however, the time for compliance will inevitably be extended.”

Flaherty said there likely will be more coal plant retirements than people think. In addition, more will be spent on retrofits than originally thought.

“Utilities might need more capital than they think because not only will retrofits likely cost more than originally anticipated, but utilities also need to build new capacity—probably gas-fired—to replace the retired units,” he said.

Future Capacity Investment

Utilities need a long-term plan—beyond 2020—that is derived without being influenced so much by natural gas price, Flaherty said.

Natural gas price is low because of:

  • Mild weather across the country,
  • Slow residential and small commercial load return, and
  • Ample U.S. supply and production—both conventional and unconventional.

“Gas still surprises me,” Flaherty said. “The economy has started coming back, and industrial load, especially in pockets in the Southeast, has come back. Small commercial and residential has been slower to come back. Even with this increase in load toward 2007 levels, gas prices have remained low—well under $3 (per million metric British thermal units (mmBtu)) today.”

This abundant gas supply could cause suppliers to begin exporting natural gas, which will put price pressure on coal plants and replacement capacity, Flaherty said. The break-even point for production ranges from below $2 per mmBtu to above $8 per mmBtu depending on the formation. Given current prices, it is difficult to see producers’ continuing to supply at the levels they have. If suppliers can get a better price on the global market—and they can—they will begin exporting natural gas.

“It may take a little while to convert the nation’s LNG (liquid natural gas) facilities from import-ready to export-ready, but it can be done and companies like Cheniere Energy are already doing just that.

“Utilities need to look beyond the current gas price and what is impacting it in the short term. They should consider it not as a default fuel, which it is now, but as a commodity whose price will fluctuate. They cannot afford to make or defer capacity plans for 2020 based on today’s low-priced gas. They should look at diversifying and balancing supply sources and shouldn’t count on these prices.”

The U.S. Energy Information Administration’s (EIA) recent early release overview of the Annual Energy Outlook 2012 (AOE2012) predicts U.S. natural gas production will continue to increase. It also, however, substantially cut the estimated unproved technically recoverable resource (TRR) of U.S. shale gas. The early overview estimates U.S. TRR through 2035 to be 482 trillion cubic feet (TCF), substantially below the estimate of 827 TCF EIA predicted in the AEO2011. The decline is largely because of a decrease in the estimate for the Marcellus shale, from 410 TCF to 141 TCF. The United States Geological Survey also made significant revisions to its TRR estimates for Marcellus shale. These reductions in shale gas estimates could impact gas price in the long term.

In addition, Flaherty said many who believe they can invest only in new gas-fired capacity assume that the geopolitical climate, especially in Iran and North Korea, will not change dramatically and a global economic downturn—a European economy collapse—will be avoided.

“Making plans for longer-term baseload needs without over-reacting to short-term prices is needed,” he said. “Utilities shouldn’t overly focus on the near term to predict the long term.”

As for nuclear, Japan’s Fukushima incident will not impact nuclear power in the U.S. as significantly as feared or as the anti-nuclear faction would hope, he said.

“Fukushima is an important reminder to the industry that a black swan event can occur and impact the industry,” Flaherty said. “It reminds us that even the low-probability vulnerabilities must be considered.”

Some older plants based in certain vulnerable locations—those near the coasts, of a certain vintage and of a particular technology design—will have decisions to make about continued operation, as will those that haven’t yet received license extensions, he said.

The few new builds that are planned won’t be impacted to any appreciable degree.

Renewable Energy

Flaherty’s opinion of renewable energy hasn’t changed since 2011. Renewable energy investments will decline, he said.

“The bloom is still off the rose,” he said. “There was a flurry of activity leading up to the expiration (Sept. 30, 2011) of Section 1603 by investors who wanted to get in before the deadline.

“The politics are against it. Congress has little appetite for renewing these subsidies given other priorities.”

Mergers and Acquisitions

Merger and acquisition (M&A) activity slowed in the second half of 2011 as utilities observed how prior announced transactions fared in securing regulatory approvals—and at what cost. The rationale for consolidation remains unchanged, however, and M&A interest is picking up again and will continue for the next several years.

“Since 2010, we’ve seen seven greater-than-$1 billion utility M&A transactions, and none have fallen by the wayside yet,” Flaherty said.

Some M&A delay occurred because utilities have been waiting to see how the Federal Energy Regulatory Commission approval unfolds with Duke Energy Corp. and Progress Energy, a merger of two very large and predominantly integrated utilities with expansive transmission assets. Other utilities want to see how states react before they make the plunge, Flaherty said.

In addition, uncertainty surrounding EPA regulations caused some M&A delay as the value of many companies would be uncertain depending on final rule adoption.

“Utilities were waiting to see what happened with EPA regulations because in most cases a lot of coal-fired baseload assets are involved in M&A activity, particularly for the fully integrated companies outside the restructured states,” Flaherty said.

From 1994 to today, the number of utilities on the Edison Electric Institute’s Utility Index dropped by about half from the more than 100 that existed at that time. Flaherty said this number will go below half the original in the next few years.

Utilities recognize that attractive and logical candidates are fewer than they once were. Some utilities that want to remain competitive in their regions think they must merge with other regional utilities to avoid getting squeezed out. M&A is part of their preservation strategies to help them remain large and competitively strong.

The drivers for utility M&A activity remains the same as last year:

  1. Create greater balance sheet flexibility,
  2. Achieve portfolio coherence (clearer portfolio),
  3. Lower costs,
  4. Diversify electricity supply risks, and
  5. Fill leadership succession gaps.

M&A allows utilities to improve business performance and strengthen their financial stability to grow opportunities. Unlike industrial sectors, the utilities industry has a strong record of producing value from combinations. And in the current environment, flattening the cost trajectory—if not outright reducing base cost levels—provides high value to customers.

2012 and Beyond

Flaherty said the economy is still recovering, but slower than all had hoped. But industrial load is on the way back, especially in the Southeast. There it’s already back to 2007 levels in some places—levels it was not predicted to reach until 2014 or 2015. In addition, the past three peaking seasons in Texas—summer 2010, winter 2011 and summer 2011—each set new all-time highs, so the usage base still exists. He questions what would have happened if high economic growth had combined with unusual weather.

“With coal-fired retirements, anticipated capacity will be tighter, which means 2013 and 2014 could be interesting,” he said.

The electric utility industry has been trying to push out the compliance timeline and create stages to help it manage cost to comply. It is trying to push the most difficult and expensive compliance issues much farther down the road.

Politics plays a key role in how successful the industry will be with this strategy; maybe not so much in 2012, but in 2013 and beyond, Flaherty said.

“If the mix remains split in the House and Senate and Obama remains in the White House, we won’t see much change,” he said. “If a Republican wins the White House, the House and Senate become more Republican or both, regulations likely will get better rationalized and relaxed.”

Whether the timeline for complying with environmental regulations changes or not, utilities will spend more in 2012 and beyond than they have the past several years. EPA regulations will result in coal plant retirements, and that capacity must be replaced, which will require capital investment.

In addition, utilities must increase their focus on changing their cost structure profile and pursuing more aggressive cost reduction because of growing regulator and customer fatigue with rate cases.

“Ratepayers are more sensitive to rate-hike requests than they recently have been because they still feel the impact of the recession,” Flaherty said. “Their paychecks are less and are not increasing, so regulators are sensing more pushback from consumers. Utilities must prove to commissions that they’re doing everything possible to operate cost-effectively and keep costs down.”

In addition, utilities will need to invest in customer service and engagement.

“Utilities should put more thought into preparing for the new customer-engagement model,” Flaherty said. “The status quo of interacting with customers only when new service is requested, bills are sent or when a problem needs immediate resolution will no longer be adequate. The utilities’ role will change.”

Customer service representatives’ roles will change dramatically. This position will evolve into a knowledge-based support position focused on providing solutions and real expertise. Customers will begin to look for more than just quick issue resolution and will value meaningful help.

Traditional customer service representatives will become customer engagement specialists who can help customers better understand their energy-use choices and help them manage the use of their installed energy management tools, such as power monitors. These customer engagement specialists must help customers make sense of how this huge amount of data collected by smart meters can provide real insight and benefit in the form of innovative customer solutions or offerings. Their role will become more like that of a high-end information enablement center similar to Google, Flaherty said.

Finally, he said a resurgence of the utility board’s role will occur in coming years, particularly in understanding and evaluating risk.

“Board members should understand that low-probability events can have very high consequences,” Flaherty said. “Fukushima is an example of this. The chances of such an incident were very low, but the ramifications of the incident were extremely high. More attention to risk will be needed. Understanding risk mitigation has never been more important.”

Flaherty predicted in 2011 that utilities would continue to face uncertainty, but would make long-term plans anyway. He was correct.

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