What Is the Future of Independent Power?

Merchant markets for independent power producers in the U.S. are unfavorable, and many companies in the sector have slumping profits—even big losses—as they ponder where to go in the months and years ahead.

Mauricio Gutierrez, CEO of NRG Energy—one of the most aggressive independent power producers (IPPs) in the U.S. for more than 20 years—stunned the industry in March 2017 when he said, “I want to reiterate my belief that the competitive power sector is in a period of unprecedented disruption. I believe the IPP model is now obsolete and unable to create value in the long term.”

It was an astonishing observation from a leader of a non-utility generating business. IPPs had flourished since the 1980s, with the impact of the Public Utility Regulatory Policies Act through the beginning of the 21st century, and the rise of competitive wholesale electric markets that have come to serve more than half of all U.S. power customers.

Figure 1-Gutierrez - NRG
1. New leadership. Mauricio Gutierrez took over as CEO of NRG in December 2015; he has been at the company since 2004. Gutierrez has acknowledged that the traditional independent power producer model is under pressure as commodity markets continue to weaken. Courtesy: NRG Energy 

Gutierrez (Figure 1) took over NRG after the company ousted iconic CEO David Crane (Figure 2) in December 2015. Crane in 12 years at NRG had taken the utility from bankruptcy, expanding it from a conventional fossil-based generation player in competitive markets, and entering into the growing and sometimes Wild West retail markets for renewables. He also was behind the creation of NRG Yield, a dividend-focused, growth-oriented company—or “yieldco”—owning and operating NRG’s power generation assets.

Figure 2-David Crane-NRG
2. Old leadership. David Crane spent 12 years as CEO of NRG Energy, leading the company out of bankruptcy and launching several other initiatives. He also steered the utility toward renewables and distributed energy—which put him at odds with company investors and eventually led to his ouster from the company. Courtesy: NRG Energy 

The market changed under Crane’s feet, as natural gas prices plummeted in the rush of cheap and fracked natural gas, lowering power prices, as electric demand plateaued, and low-cost and subsidized solar and wind power undercut NRG’s financial performance. The company lost $900 million in 2016. “Changes in fuel mix, consumer preference, technological innovation, and increased distributed generation have put pressure on the traditional IPP model, particularly as commodity markets continue to weaken,” Gutierrez said.

Those trends have continued.

Differing Views

What is the future for independent power in the U.S., which has transformed generation markets and technologies for decades? Is Gutierrez an oracle, or are the headwinds facing IPPs resistible?

Taking an unsurprisingly optimistic view is John Shelk, head of the Electric Power Supply Association (EPSA), a Washington lobbying group for IPPs. “The prospects are challenging for all power producers, IPPs and non-IPPs,” Shelk told POWER in an email exchange, “for a host of well-recognized and well-documented reasons: essentially flat load growth; excess supply; changing resource mix; more options for consumers; technology; desire for cleaner energy sources,” and so on.

Ultimately, said Shelk, IPPs will survive, as they “own, operate, and continue to develop significant amounts of power assets, especially in the eastern [regional transmission organizations], Texas, and California, that are essential to reliable operation of the grid in those regions. The public power challenges will continue to be many but these assets are largely needed and deserve an opportunity to compete in well-functioning markets.”

A less self-interested short-term assessment comes from the bond rating agency Moody’s Investors Service, which has given a negative outlook for unregulated power in 2018. Moody’s noted that “demand is weak, markets are still oversupplied and wholesale prices remain low. Credit positive forces are developing in the industry, but they are not strong enough to change our view.”

Moody’s cites the following trends that work against independent power:


Low prices for power and natural gas. Henry Hub gas prices continue to hover at about $3/MMBtu, and on-peak prices for power “remain under pressure from lower-cost shale gas and an abundance of wind and solar generating facilities.”

Demand is weak in oversupplied markets. Energy efficiency is holding down electricity demand, notably in the PJM Interconnection, the nation’s largest wholesale competitive market. Coal-plant retirements in the Electric Reliability Council of Texas (ERCOT)—including a recent decision by Luminant to retire its 1.9-GW Monticello coal-fired plant—“may curb oversupply in that region, but renewable energy sources will still pressure prices.”

Merchant plants face greater inherent risks than conventional, regulated power companies. The vertically-integrated monopoly firms “may benefit from retail operations and have already implemented cost or debt reduction strategies.”


A June paper by the D.C. law firm of Wilkinson Barker Knauer (WBK) and the Connecticut-based Power Research Group (PRG), “The Breakdown of the Merchant Generation Business Model,” noted, “Over 40% of U.S. power demand is supplied by merchant generators rather than regulated utilities. During the advent of electricity restructuring in the 1990s, private generators funded by private risk capital were going to be the future of electric generation in the U.S. It has not turned out that way. To the contrary, some large merchants may be headed toward a second round of bankruptcies in less than twenty years.”

The paper says, “The key weakness of the merchant generation business model is that generators’ revenues generally do not cover the all-in cost of supply, which includes the cost of capital recovery as well as the variable cost of operation. Power generation is characterized by high capital costs for new production plants and low variable costs of production, contributing to a highly cyclical pattern of prices, profit and investment. When capacity is scarce, electricity prices (and capacity payments, when available) must rise to a level that allows recovery of the all-in cost of supply—the cost of building as well as operating a new power plant—if new power plants are to be built. As capacity is added in response to this price signal, however, the scarcity is alleviated, and competition among generators then drives the price of power down to its variable cost of production—a fraction of the all-in cost.”

How bad is it for the non-utility power sector? In 2016, Calpine, one of the first firms into the non-utility market, saw profits of $92 million, down from $235 million in 2015. NRG reported a loss of $891 million in 2016 (down from $6.4 billion in 2015). Dynegy’s 2016 loss came to $1.24 billion, versus a 2015 profit of $50 million. NRG’s GenOn Energy merchant subsidiary, with 32 gas, coal, and oil generators totaling some 15 GW of capacity across 18 states, filed for bankruptcy. Last summer, Calpine agreed to be taken over by private equity firm Energy Capital Partners for $5.6 billion. Last fall, Dynegy (Figure 3) agreed to merge with Vistra Energy for $10.7 billion. In November, Exelon non-utility generating subsidiary ExGen Texas Power filed for Chapter 11 bankruptcy protection.

Figure 3-Dynegy
3. Dynegy merges with Vistra. Dynegy Inc. and Vistra Energy agreed to merge late in 2017, creating a company with a projected value of more than $20 billion. The companies said the deal was designed to strengthen their balance sheets and combat the market issues affecting power generators in competitive markets. Courtesy: Dynegy 

Changing Regulations

In addition to boom-and-bust pricing, the WBK/PRG report highlights the trend toward reregulation among some states to boost favored generating technologies, which suppresses wholesale costs while increasing the cost of doing business. New environmental regulations add to the problem. “Increasingly stringent regulations governing air emissions and coal ash disposal and limiting the use of once-through cooling water systems add substantially to the going-forward cost of steam turbine generators,” says the report. “Simultaneously, by supporting the construction of new renewable resources, state renewable generation mandates and federal tax credits have added zero variable cost generating assets at the bottom (lowest cost part) of the power supply curve.”

Two states—Illinois and New York—last year adopted subsidies, paid by ratepayers, to subsidize nuclear plants unable to compete in wholesale interstate markets. They created “zero emissions credits” designed to account for the value of zero emissions of carbon dioxide in the wholesale bidding process, using the Obama administration’s calculation of the “social cost of carbon” as the basis for the subsidy.

Adding to the problems facing the IPPs, the Trump administration’s Department of Energy (DOE) late last year had the Federal Energy Regulatory Commission (FERC) propose a rule aimed at preserving uncompetitive coal and nuclear plants by awarding those units with a 90-day fuel inventory full-cost recovery in competitive markets. The basis of the DOE proposal was that competitive markets don’t recognize the value of “resilience,” although DOE offered no quantifiable definition of the term.

EPSA’s Shelk described the DOE proposal as an “arbitrary and unsupported federal mandate to pay a regulated cost-of-service rate only to power plants with 90 days’ fuel on-site at great expense to consumers and competition.” Responding to POWER after comments came into FERC on the proposed rule, Shelk said they demonstrated “unprecedented opposition,” including among “consumer groups, state regulators, the regional grid operators, market monitors, environmental groups, [and] the fuels that are competitive.”

Should FERC adopt something close to the rule Energy Secretary Rick Perry was pushing, Shelk said, “There will be a rush to the D.C. Circuit [Court of Appeals] by a zillion lawyers and their clients based on the extensive comments on the glaring legal deficiencies in the [notice of proposed rulemaking], which is one of the reasons FERC is highly unlikely to adopt it or anything like it that so clearly violates the legal requirements of the [Federal Power Act] and the [Administrative Procedures Act].”

Tearing Down the Monopoly Model

For nearly the first 100 years of its operation, the U.S. electric power industry was founded on the idea that generating, transmitting, and distributing electricity from the power plant to the customer was a natural monopoly. From 1882 and Thomas Edison’s Pearl Street generating station until the late 1970s, the vertically-integrated monopoly, largely regulated by the states, was the dominant model for the industry, although government-owned systems and customer-owned systems provided a modicum of competition to the conventional model.

By the 1970s, it was becoming clear that the conventional model of the integrated monopoly had developed problems. Under state cost-of-service regulation, companies had an incentive to “gold plate” their generating plants, building more expensive capacity in order to earn a return on the state-approved cost. At the same time, the nuclear power construction business crashed as costs soared, electricity demand did not grow according to earlier industry estimates, and consumers were left holding a bag of expensive, unfinished nuclear plants.

Economists and industry analysts began arguing that there was no reason that power plants were natural monopolies. In a different economic environment, private parties could build generating plants, taking the economic risks that previously had been borne by utility customers. That revolutionary concept took hold.

In 1978, Congress passed the Public Utility Regulatory Policies Act (PURPA), which created a structure for non-utility generating plants. PURPA was aimed at promoting energy conservation and the use of domestic renewable energy. A provision of PURPA—which turned out to be its most significant—encouraged the development of “cogeneration” plants. The idea was that plants that produced both electric power and industrial steam were more efficient than utility steam-generating plants.

Under PURPA, if a generator was able to supply 5% of its steam output to a non-utility use, such as an oil refinery or a manufacturing plant, it would be entitled as a “qualifying facility” to sell its electrical output at a favorable rate, known as the “avoided cost” rate, based on what the electric utility would have had to pay for the same amount of generating capacity in a utility-owned plant.

These provisions turned out to be the proverbial camel’s nose under the utility monopoly tent. Entrepreneurs saw a market opportunity. Among the first to take advantage of this new federal regulatory rule was Roger Sant, who had been an administrator in the Federal Energy Administration (FEA, a predecessor to the DOE) in the Nixon and Ford administrations. In January 1981, Sant was the co-founder of The AES Corp., based in Arlington, Va., along with Dennis Bakke, another FEA veteran.

AES, originally a consultancy, quickly moved to take advantage of the PURPA cogeneration rules. In 1985, AES built its first power plant, in Texas, to serve the oil and gas industry with industrial steam and Texas utilities. Other companies followed, including Dynegy, Calpine, and many who did not survive the intense competition that followed.

‘PURPA Machines’

As the cogeneration markets exploded, conventional utilities began complaining about what they called “PURPA machines”—generators, usually gas-fired, that sold their PURPA steam requirements to what the utilities believed were sham customers, such as fish farms and greenhouses. At the same time, the municipal utilities and rural electric cooperatives complained that conventional utilities were using their monopoly over transmission and distribution to abuse the public power systems. Public power began arguing for “wholesale wheeling,” the ability of the municipal systems and co-ops to have access to electricity from other utilities, wheeled over the monopoly systems.

In 1989, the now-defunct congressional Office of Technology Assessment produced an influential report, “Electric Power Wheeling and Dealing,” which concluded: “Concerns that the bulk power system (generation and transmission) is inherently incompatible with competition do not appear to be well founded. The system can be made to work under any of the institutional/regulatory arrangements considered in this study. Problems and issues will arise with widespread competition, but they will be much less technical than political and institutional.”

That analysis formed the basis of the 1992 Energy Policy Act, in which Congress gave FERC the authority to implement competitive markets. In a series of subsequent orders, FERC built the foundation for today’s electricity industry (see sidebar), including competitive wholesale markets now serving more than half of U.S. electric utility customers. This “deregulation” led to a boom in non-utility generation, as many states adopted laws requiring their monopoly utilities to spin off generating assets into independent businesses.

A Tale of Two IPPs

Among the diminished population of independent power producers (IPPs) left standing during the recent market woes are NRG Energy and Dynegy. Each has taken a different path, though they have historic similarities, beginning with lots of coal and gas generation.

Energy Wire noted in 2014 that the two companies “have begun growing in drastically different directions, with one continuing to lay its bet almost entirely on fossil fuels and the other making huge, daring investments in solar farms, carbon-capture plants and electric cars.” Dynegy was the traditionalist while NRG was exploring new frontiers with renewables (Figure 4).

Figure 4-NRG Solar
4. Exploring new frontiers. NRG’s investments in renewables, including solar power, have continued even under new leadership. The company says its utility-scale projects today deliver more than 1,200 MW of power. Courtesy: NRG Energy 

Three years later, it isn’t clear that either firm will survive the current shakeout of independent power. Both companies are facing existential moments; each has survived bankruptcy reorganization. NRG filed for bankruptcy protection in 2002; Dynegy nearly sought protection in the same year, and eventually went through Chapter 11 in 2012.

Today, Texas-based Vistra Energy, parent of TXU Energy and Luminant, both of which operate in the unique Texas market with competitive generation and integrated retail operations, is proposing to take over Dynegy in an all-stock transaction. In a press release, Vistra said, “The combination of Dynegy’s generation capacity and existing retail footprint with Vistra Energy’s integrated [Electric Reliability Council of Texas] model is expected to create the lowest-cost integrated power company in the industry and to position the combined company as the leading integrated retail and generation platform throughout key competitive power markets in the U.S.”

Dynegy has also launched an effort in the Illinois legislature for a bailout similar to what the state agreed to provide to Exelon to help its uneconomic nuclear units bid into competitive wholesale markets. Dynegy operates eight coal-fired plants in Illinois and would like lawmakers to approve its effort to pull out of the Midcontinent Independent System Operator and establish an Illinois-only market.

After ousting the flamboyant and aggressive CEO David Crane, NRG has moved to refocus on conventional merchant generating by unloading its solar businesses and ending NRG Yield, seeking $1 billion in savings. NRG lost nearly $900 million in 2016, according to the company’s financial statement.

Two activist investors, billionaire hedge fund manager Paul Singer, and Charles John Wilder of Bluescape Energy Partners (Figure 5), have led the ongoing NRG transformation into a more conventional IPP, a segment of the electric industry that CNBC said “has humbled some of the world’s savviest investors in recent years.” Singer’s Elliott Management owns about 6% of NRG, and Bluescape owns about 3%.

Fig 5_Singer and Wilder
5. The activist investors. Paul Singer (left) and Charles John Wilder (right) have led the movement to return NRG to a more conventional IPP structure after the ouster of former CEO David Crane. Singer’s Elliott Management owns about 6% of NRG; Wilder’s Bluescape Resources owns about 3%. NRG’s investments in renewables, including solar power, have continued even under new leadership. The company says its utility-scale projects today deliver more than 1,200 MW of power. Courtesy: Wikipedia (Singer), Bluescape Resources (Wilder)

In November, pondering NRG’s transformation plan, the Market Realist website said, “After divesting its renewables and yieldco businesses, exposure to merchant generation will likely increase, which could make the company even riskier.”

How Do IPPs Survive?

What’s ahead for IPPs, and can they survive the gale-force market winds buffeting them?

The immediate challenge is the Trump administration’s proposal at FERC for special treatment for coal and nuclear plants based on “resilience.” FERC is not expected to adopt a rule similar to what Energy Secretary Rick Perry proposed, even though the commission now has a Republican majority. Republican commissioner Robert Powelson, a former Pennsylvania utility regulator, has made it clear that he is not interested in a broad attack on competitive markets.

EPSA’s Shelk said his group and others “have argued for years (with EPSA the first to do so in December 2013 at FERC) that energy and capacity market rules need to be reformed in light of the changing resource mix. They also need to insulate those who rely on market revenues from distorting impacts of state subsidies such as [zero emissions credits] and out-of-market contracts. FERC was already working on these issues well before the ill-advised DOE [notice of proposed rulemaking] and EPSA hopes and expects FERC will accelerate that work as it would have done anyway had the DOE [plan] never been put forward.”

A moment of optimism for IPPs came last fall when Eversource New Hampshire, a conventional state-regulated monopoly, filed a plan with the state to spin off its remaining utility generating resources—five fossil-fueled plants totaling 1,130 MW for $175 million, and nine hydro stations totaling 68 MW for $83 million. It is part of a settlement with the New Hampshire Public Utility Commission, moving generation into the ISO-New England market in an attempt to lower consumer prices.

Last fall, the Motley Fool investment website advised IPPs to “look to new technologies for growth.” The posting by analyst Travis Holum said that “renewable energy has been surprisingly damaging and it’s this new energy source that IPPs need to adapt to or face the very real risk of going out of business.” Holum said, “It’s time to think innovatively about the future of energy and IPPs will be in trouble if they don’t. Energy storage is a great place to start looking for struggling IPPs, and if they play their cards right, they could develop a profitable business driving more renewable energy adoption, rather than watching renewables slowly kill their traditional power plant business.” ■

Kennedy Maize is a long-time energy journalist and frequent contributor to POWER.