Xcel Energy is manipulating Colorado’s renewable energy policies to reap profits from ratepayers above and beyond the allowed amount, according to a Public Utilities Commission renewable energy expert.

“It is now well known that [Xcel] has far exceeded its available budget for renewable resources and that the Company has been loaning money to the [Renewable Energy Standard Amendment] fund – and earning its rate of return on those funds – to allow it to acquire more renewable resources than it needs for RES compliance,” renewable energy expert Richard Mignogna testified last month.

He questioned whether the PUC should put the brakes on its demand for wind. Mignogna argues that Xcel uses the interest it collects from ratepayers for its solar commitments to invest in wind resources that it then sells to California in order to turn a tidy profit.

“The Company’s renewable energy acquisitions have already far exceeded its RES obligations. Exacerbating this problem and creating a perverse incentive is the fact that the Company is earning a profit on the sale of the excess Renewable Energy Credits which were paid for with interest by ratepayers. The Company is profiting on both ends of this deal and has exercised inadequate fiscal restraint,” he wrote March 16 on the PUC’s latest Electric Resource Plan.

Xcel, aka Public Service Co., has exceeded its available budget under the Renewable Energy Standard Amendment fund, which he claimed is projected to end 2011 with a $97 million deficit.

“While PSCo typically argues that it is only charging customers the two percent allowed by the statute, that argument is disingenuous. As we now know, the Company has been loaning money to the RESA, earning its rate of return on the funds advanced, so that it can acquire more RECs than it needs only to sell them into California so that it can then claim a percentage of those proceeds,” Mignogna wrote.

Xcel spokeswoman Michelle Aguayo blamed the negative RESA balance on payments the company had been making to the Solar Rewards Program ― payments it recently reduced ― and she said the shortfall has “relatively nothing to do” with excess renewable wind credits it has sold to California.

The renewable energy wind credits Xcel is selling are not funded out of RESA, she said. They were acquisitions that the PUC previously ordered based on the 2005 All Source Request for Proposals.

“Selling RECs into CA is a win-win for both our customers and the Company,” Aguayo wrote in a recent email interview. “We are under no obligation to seek out buyers of RECs but we believe it is a prudent thing to do. We negotiate a good price on behalf of our customers. Both of these actions produce margins that are shared back with our customers. Clean energy is good for Colorado. The legislature gave us limited funds that we could use to purchase renewable energy. By selling excess RECs we are stretching this very limited fund of money. This is not being disingenuous.”

Still, in light of the acquisition of more renewable resources than is actually mandated, Mignogna questioned “whether acquiring any resource in the 2011 Wind RFP is prudent. The company should not be permitted to advance funds, and earn interest on them, simply to acquire resources that it may then sell into other jurisdictions so that it may profit additionally from the sale,” he testified.

Xcel, meanwhile, is planning to double its wind resources by 2020.

In a settlement with Energy Outreach Colorado and the Colorado Energy Consumers, Xcel agreed to only seek an annual electric rate increase of $136 million, mostly to cover more than $1.7 billion the company invested in the new Comanche 3 coal-fired power plant near Pueblo, two new gas-fired power plants at Fort St. Vrain, a smart-grid project in Boulder and other power line and distribution expenses.

If approved by the PUC at final deliberations set for Dec. 3, the average residential customer will see an increase of $4.66 a month beginning Jan. 1, and small business customers will see an increase of $7.16 a month. Xcel had originally sought a nearly $180 million increase, which would have upped typical residential rates by nearly $5 a month.

This settlement is similar one last summer when Xcel reduced its rate-increase request from nearly $160 million to $112 million, but critics at the time claimed even that amount was too much given the company’s ill-advised investment in coal, which may spike in price if the Obama administration successfully pushes through climate change legislation.

Xcel, however, defends the state-of-the-art Comanche 3 project, which is set to come on line by the end of the year.

“We see this as a significant step to continuing our ability to provide reliable, reasonably priced electric service,” said Tim Taylor, CEO of Public Service Co. of Colorado, an Xcel Energy company. “Comanche 3 is a great investment for customers. Being able to use low-cost coal to provide base-load power is important for our Colorado customers. It also allows us to take the next step and begin retiring some of our older, less efficient coal-fired power plants to continue reducing our carbon dioxide emissions.”

Xcel has also taken heat for trying to pass on questionable travel and entertainment expenses to ratepayers – a move it quickly backpedaled on when consumer groups brought the charges to the attention of the PUC.

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In an exhibit filed with the Colorado Public Utilities Commission on the last day of a rate-case hearing in Denver last week — in which Xcel sought nearly a $180 million rate hike — the state’s largest power provider detailed expenses totaling more than $120,000 that it hoped to pass on to its 1.3 million Colorado customers.

Some of those 2008 travel and entertainment expenses include $9,524 of a $41,890 bill for a board retreat at the plush St. Julien Hotel and Spa in Boulder; $5,410 of a $9,721 bill for Colorado Avalanche games; $19,323 of a $26,639 bill for “other employee related sporting activity”; $3,746 of an $11,958 tab at McCormick’s Fish House and Bar in Denver; and $3,458 of a staggering $15,211 bill at Frasca restaurant in Boulder.

Dennis Kelly, an attorney in Arapahoe County representing a grassroots activist group called the ArapaHOPE Community Team, tried late last month to introduce testimony from the Minnesota attorney general in a similar rate case in May for Xcel subsidiary Northern States Power Company before the Minnesota Public Utilities Commission.

Kelly said the Colorado PUC — which is in charge of state oversight of the Minneapolis-based, investor-owned utility — refused to enter the testimony from the Minnesota case into the Colorado docket but did request information from Xcel detailing whether there were similar expenses being passed on to Colorado ratepayers.

“I have no problem with travel and entertainment expenses as long as they’re reasonable and justified, but some of these go beyond the pale of what’s reasonable and what’s justified,” Kelly said. “It just seems like an awful lot of money for the ratepayers to be paying for. If the company wants to do it, that’s fine, but it should be the shareholders, not the ratepayers.”

In the Minnesota case, Xcel reportedly axed $3.9 million from its rate increase request of $156 million after Minnesota Attorney General Lori Swanson questioned how a number of expenses being passed on to ratepayers had anything to do with providing power.

“Xcel has charged Minnesota electric ratepayers — and likely Minnesota gas ratepayers — for expenses that are not reasonable or necessary for the provision of electric services,” the OAG’s office concluded. “The OAG believes it would be beneficial for the Minnesota Public Utilities Commission to order a complete review of these expenses …”

Kelly and other “interveners” in Xcel’s Public Service Company (PSCo) rate case want the Colorado PUC to set strict guidelines for such expenses in the future. They say the PUC apparently does not have any such parameters for T&E expenses. Matt Baker, one of three PUC members, said Monday he could not comment on an open docket.

“That is an active issue in the rate case, so I can’t talk about it, but it has been brought up,” Baker confirmed. Xcel’s second rate case in the last year – it received a $112 million increase just last summer – should be decided in the next two weeks after all the parties submit position statements.

In a statement issued Tuesday afternoon by Xcel in response to inquiries from The Colorado Independent, a spokesman for the utility called the expenses “a reasonable cost of doing business” and said the company has offered to remove them.

“In response to the issue raised by parties in the case, PSCo [Xcel] performed a detailed analysis to see the amount of these types of expenditures included in its historic test year. The number was small — $121,000, which is .004 percent of customer bills,” spokesman Tom Henley wrote in an e-mail.

“The commission has never disallowed these sorts of expenditures in the past and the company finds that these occasional expenses are a reasonable cost of business, but offered to remove the costs from its historic test year during the hearings. The company will offer to remove the same amount from its forecasted test year, meaning that customers in Colorado will not be paying for these types of expenses.”

Kelly said that at the very least the PUC should establish a rule barring alcohol costs from being passed on to ratepayers.

“These people have no sense of propriety given the current situation in our country, but they need to ask themselves if they really need all of this that they’re asking for,” Kelly said. Leslie Glustrom of Boulder-based Clean Energy Action, another intervener in the rate case, seconded that sentiment.

“In this particular case, if those expenses go into the rate base, the message it sends is the more you drink, the more you earn,” Glustrom said. “The commission can set a clear policy of, ‘Go ahead, make your deals over wine and dinner if you want, but don’t charge it to ratepayers.’ If they want to do that, let their shareholders pay for it.”

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Representatives of companies building utility-scale renewable projects like the 8-megawatt SunEdison solar plant in Colorado’s San Luis Valley say sun and wind generation facilities can be permitted and built in under two years, but transmission lines can take more than a decade to become reality.

That transmission bottleneck, which even the Governor’s Energy Office admits is a serious impediment to its “New Energy Economy,” is exacerbated by issues of simple geography.

“You can put wind and solar only where the wind blows and the sun shines, whereas with coal and gas and nuclear, you can build those plants wherever you want and just build a rail spur, or truck in the fuel and you’re in business,” said Craig Cox of Interwest Energy Alliance, a regional association representing top utility-scale wind and solar companies.

“With renewables you have to build exactly where the resource is, and where the resource is in Colorado is where the people aren’t. So in eastern Colorado, transmission was always built for populations of thousands, and what we need is to serve populations of millions on the Front Range and throughout the West.”

The same is true of solar-rich areas like the far-flung San Luis Valley on Colorado’s Western Slope.

Interwest two years ago was instrumental in passing state Senate Bill 100, which allows the Colorado Public Utilities Commission (PUC) to approve transmission construction before the actual generation facility goes online.

The measure also allows utilities such as Xcel Energy to charge customers for that transmission before having to build a rate case.

“But since the passage of that law we haven’t seen much in the line of proactive transmission built for renewables in Colorado by Xcel Energy, which was the primary partner in passing this bill,” Cox said.
There have been two filings for increased transmission since the passage of SB 100: the line from the San Luis Valley to Calumet (near Walsenburg in southern Colorado), a joint project with Tri-State Generation and Transmission, and Xcel’s upgrade of the Pawnee to Smoky Hill line on the Front Range.

Xcel officials argue they have filed transmission plans under SB 100 and taken steps to ensure enough capacity through 2015. Xcel spokesman Joe Fuentes did not comment directly on the perceived transmission bottleneck, but instead referred to a response the utility filed with the PUC to an Interwest motion earlier this month seeking to hasten Xcel in the transmission-planning process.

“In essence, Public Service [Xcel] believes that it has a fundamentally different view of the process than Interwest. Interwest appears to operate by the notion that transmission can and should be constructed well in advance of any actual generation connection need,” the response read. “While Public Service acknowledges that the SB-07-100 framework is different than past planning, there still needs to be some assessment of need and prioritization.”

Fuentes did note that Interwest’s motion to compel more aggressive transmission planning and convene hearings at which Xcel executives would be required to explain the planning process was denied by the PUC.

Interwest attorney Ron Lehr, a former chairman of the PUC, said Xcel is not developing a comprehensive transmission plan or increasing transmission capacity in Colorado nearly as rapidly as it is in Minnesota, where the company is based. Part of the problem, he said, is that Xcel, Colorado’s largest utility, doesn’t coordinate well enough with Tri-State, the state’s second largest utility.

“You have this kind of uneasy coordination between the two utilities who do this kind of work in Colorado,” Lehr said. “If you ask yourself, does the state have a coordinated, long-range transmission plan, the answer would be no, because we have two of them, and by definition if you have two plans, you don’t have one plan.”

Lehr added that planning through 2018 or even 2015 isn’t nearly fast enough to fix the state’s transmission bottleneck to renewable energy resources.

“If it takes five to seven years to build a transmission line, once the planning’s done and the approvals are made, and the planning and approval might take two or three years, then we’ve got what we’re calling ‘just-in-time transmission planning,’ or if you look at it a little more cynically, you would call it ‘not-quite-in-time’ transmission planning.”