About 80 miles separate Nebraska’s two nuclear power plants, but they might as well be separated by a light-year, according to a World-Herald analysis of costs to produce electricity at each plant.

It cost the Nebraska Public Power District about $40 in 2015 to generate a megawatt-hour of electricity at its Cooper Nuclear Station south of Brownville.

At the Omaha Public Power District’s Fort Calhoun nuclear plant, that same amount of energy cost about $71 to generate last year, underlining OPPD’s decision to permanently shut Calhoun at the end of this year.

Still, the Nebraska nuclear plants share one distinguishing characteristic: The top nuclear officer for each facility is an employee of neither OPPD nor NPPD. Each contracts with an outside firm to operate its nuclear facilities.

In fact, Cooper and Calhoun are the only two nuclear plants in the country that have ceded management of day-to-day operations to outside experts, according to a World-Herald survey of the federal nuclear regulator. Both publicly owned plants were brought back from the brink of earlier shutdowns with the help of for-profit companies — and for a big price: contracts that pay the outside companies more than $1 billion over 20 years.

The Omaha utility’s board on June 16 voted unanimously to close down its lone nuclear plant by year-end, citing insurmountable economic challenges stemming from low prices on the wholesale energy market and outsize expenses at the country’s smallest nuclear plant.

It’s not the only such announcement of a U.S. nuclear plant closing — at least six are slated to shut in the next three years.

But that’s where NPPD diverges from its cousin up the river. Its management and board say they’re bullish on the future of Cooper — by this time next year, the state’s sole operating nuclear power plant.

“We have no intention of closing Cooper,” NPPD Board Chairman Ken Kunze said. “I think as time goes on and people realize the wind doesn’t always blow and the sun doesn’t always shine, it’s kind of nice to have a plant of 800 megawatts chugging along to keep the lights on.”

The NPPD nuclear plant’s carbon-free footprint and the generating diversity — it’s not coal or gas or wind, for instance — that it affords the statewide utility’s customer base are chief among the strengths touted by its supporters. Those same arguments — the reliability and emissions-free nature of nuclear power — for decades kept OPPD’s troubled Fort Calhoun in the mix.

But that plant still could not overcome the economic challenges it faced.

So what gives at Cooper, which sits on the same river in the same state and sells excess power into the same marketplace as Fort Calhoun?

For starters, NPPD’s 810-megawatt nuclear plant is far larger than OPPD’s 478-megawatt one. In terms of generating capacity, pitting Cooper against Calhoun is like matching up a 200-pound heavyweight boxer with a 115-pound flyweight.

In terms of actual output, Cooper’s 2015 generation amounted to 6.1 million megawatt-hours of electricity, or 74 percent more than the 3.5 million units at Calhoun last year.

And it produces 74 percent more electricity than Calhoun with eight fewer employees: NPPD counts 686 full-time employees at Cooper versus OPPD’s 694 at Calhoun.

“You don’t have to be the lowest-cost resource” to survive in today’s challenging energy market, NPPD President and Chief Executive Pat Pope said. “But you have to be in the ballpark.”

Cooper, Pope says, is very much in that ballpark.

That’s not the case for Fort Calhoun and 10 other nuclear plants that have either closed or announced plans to close since late 2012.

The high fixed costs to operate such facilities mean additional and costly expenses can add up in a hurry. That’s doubly true for small, single-reactor plants like Fort Calhoun, where costs to produce electricity are virtually double the industry average of $35.50 per megawatt-hour — an average that even Cooper is above.

In markets where energy producers compete with other utilities to secure power supply contracts, electricity from cheaper natural gas and renewable sources has crowded out money-losing nuclear plants, leaving them with little choice but to close. Even in Nebraska, where utilities enjoy a monopoly thanks to the state’s public-power structure, players like OPPD and NPPD sell their excess power into competitive markets.

On those markets, an influx of cheap natural gas and increasing amounts of wind-powered electricity helped knock down NPPD’s surplus sales 22 percent to $134.6 million last year. The utility’s overall revenue fell almost 8 percent to $1.1 billion.

Those factors also put a hole in OPPD’s 2015 budget, which fell short of projections on virtually flat revenue and revenue declines on the wholesale market. The Omaha utility last year had to hike rates to make up the difference and remains in cost-cutting mode.

NPPD’s Pope remains unfazed: Cooper performs at a high level and goes off-line for refueling once every 24 months instead of every 18 months like the plant upriver; it has not recently run afoul of regulatory oversight and operates safely; and its costs to produce energy are better than Fort Calhoun’s.

Consider it a product of its size (despite still being relatively small compared with the nation’s largest nuclear plants) combined with the outside expertise that more than $20 million a year can buy.

“I know natural gas is near all-time lows, and that’s fine, because I’m taking a longer-term value of nuclear instead of competing against whatever fuel is the lowest-cost right now,” Pope said.

Natural gas prices have fallen more than 50 percent over the past three years, making electricity fueled by the gas the power of choice for many. On March 4, prices bottomed at an 18-year low.

So even though power can be purchased on the open market for around $20 a megawatt-hour — higher than the $40 that NPPD can produce it for at Cooper — Pope says natural gas might not always be that cheap, and it’s good to have Cooper online to weather the swings in commodity markets, the uncertainty of wind and the regulatory issues surrounding coal. It’s licensed to operate until 2034.

Still, some of the same industry watchers that have long had Fort Calhoun on watch lists of the most endangered nuclear plants in the U.S. also have included Cooper.

Said Moody’s Investors Service analyst Dan Aschenbach: “Lots of people have felt that both units, and primarily Fort Calhoun, should have been shut down 10 years ago.”

One of them is Chris Gadomski, head of nuclear research at Bloomberg New Energy Finance in New York.

“I thought Calhoun was going to go earlier than it did,” Gadomski said last week, adding that Cooper is in a better position because of its size but still faces the same obstacles that helped sink its cousin.

Those challenges that smaller plants face are magnified because of scale issues and a relative inability to spread their costs around.

For example, Gadomski said, “When you have a reactor like Peach Bottom (in Pennsylvania), that’s something like 3,900 megawatts on-site. That’s five times the output of Fort Calhoun, but they don’t have five times the security costs.”

Of seven facilities Gadomski included on a watch list published with a research note in April, four have since announced plans to close. All of those announcements — Exelon Corp.’s Quad Cities and Clinton plants in Illinois; Fort Calhoun; and Pacific Gas & Electric’s Diablo Canyon facility in California — came in June.

That leaves Exelon’s Byron Generating Station, a plant facing the same market pressure that doomed its Clinton and Quad Cities counterparts; Entergy’s Indian Point, which is in the middle of a protracted and politically fraught relicensing process; and Cooper, the smallest of the lot, on his list.

“It’s clearly not making any sense to operate if you can buy power for $19 or $20” on the open market, Gadomski said.

The Bloomberg analyst qualifies that criticism by noting there has to be a clean replacement for these doomed reactors. At least in the Midwest, it appears that will be the case. Of the capacity gap planned to be filled in the wake of Fort Calhoun’s impending retirement, the vast majority will be replaced by wind power.

That’s also true to an extent in Iowa’s neighbor to the east, Gadomski said: “All the transmission lines they built years ago to take electricity from Quad Cities to Iowa are now taking electricity back to Illinois from Iowa wind farms.”

To be sure, today’s economic challenges from renewable energy and a gas glut are decidedly different issues from those Nebraska’s nuclear plants faced during other tumultuous periods in the last 15 years.

Both plants in that time have battled their share of problems: Cooper was among the first nuclear plants in the country to land on the federal regulator’s then-new watch list of plants with serious performance problems.

In early 2002, the Nuclear Regulatory Commission dinged NPPD for frequent problems over its inability to fix problems after they were identified and other performance issues. The frequency of those findings and Cooper’s inability to fix them had the plant one step away from an NRC-imposed shutdown.

It wouldn’t get the “all clear” from the regulator for almost three years. Things had been bleak enough for long enough that it was apparent the plant was at a crossroads.

Said Gary Thompson, the nuclear committee chair and longest-serving NPPD board member: “When we really had some difficulties (in the early 2000s) … clearly there were some issues from which there was a feeling that NPPD would be better off not having Cooper in its fleet.”

The board decided to press on, anyway, hiring Louisiana-based Entergy in July 2003 to run the nuclear plant on NPPD’s behalf. The original 10-year agreement was worth $211 million.

Asked whether the deal was “do-or-die” for Cooper, Thompson said: “I think it was. We were at a point where our customers and management were really thinking maybe we ought to try to get rid of Cooper.”

So well did things go that NPPD board members in December 2009 authorized a 15-year extension that will pay Entergy an additional $422 million through 2029.

Fort Calhoun at the time of Cooper’s initial plight, meanwhile, was classified among the best-performing plants in the country.

Within 10 years, the tables would turn.

Fort Calhoun in 2011 was sent reeling from historic Missouri River flooding and an electrical fire that precipitated a stern regulatory crackdown. The NRC’s findings and OPPD’s work to fix them kept the plant off-line for 2½ years.

The debacle ended up costing nearly $300 million and left OPPD with an agreement similar to the one between NPPD and Entergy.

OPPD entered a 20-year “operating services agreement” with Chicago-based Exelon in September 2012, after the federal regulator compiled a laundry list of more than 450 deficiencies that had to be corrected before Fort Calhoun could come back online.

The Omaha utility has declined repeated records requests to share details of the contract, but its value has been estimated at $400 million over 20 years; invoices provided to The World-Herald show that OPPD has paid Exelon more than $87.5 million through May 2016. NPPD provided its contract with Entergy at The World-Herald’s request, but redacted all financial figures. The contract’s total dollar amount was found on another document filed by its board of directors.

No other nuclear plants in the country operate under such agreements.

Where recovery costs and market forces eventually torpedoed Fort Calhoun, the NPPD plant “turned the corner pretty dramatically,” said ratings analyst Aschenbach, and “that helped with their cost structure.

“Having a larger plant, they’re over 800 megawatts, and that helps to keep costs on a per-unit basis down,” he said.

But that’s not all: Where OPPD sunk almost $400 million into critical equipment replacement and refurbishing in 2006 to live through the end of its extended federal license in 2033, NPPD balked on a similar project in 2012.

Cooper stood to gain 146 megawatts of capacity through a so-called “uprate” that would have cost an estimated $243 million. But when a more detailed analysis pegged the costs of such an undertaking at north of $400 million, district officials put the project on the shelf. “It was a prudent call,” Aschenbach said.

Despite the blessing of the NPPD board to go ahead with the upgrade in 2012, Pope said, management had second thoughts about proceeding and did “a much harder scrub of the numbers.”

Other utilities seeking similar refurbishments have not been so fortunate.

By the time Minneapolis-based Xcel Energy got through an uprate at its 2,004-megawatt Monticello nuclear plant near the Twin Cities, costs had more than doubled from an estimated $320 million in 2008 to $748 million when it finished in 2014.

Projected costs for a similar and more recent upgrade at Xcel’s other nuclear plant — the two-unit, 1,677-megawatt Prairie Island near Minneapolis — have mushroomed from an estimated $175 million to $478 million. Xcel will study a premature shutdown of that facility.

“We did a 180. I’m glad we did,” Pope said. “It was big bucks.”

Contact the writer: 402-444-1534, cole.epley@owh.com

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