Shoshone: “It’s an important plant for us [@XcelEnergyCO]” — Jerome Davis #ColoradoRiver

September 2, 2014

From The Grand Junction Daily Sentinel (Dennis Webb):

A Glenwood Canyon hydroelectric power plant with a controlling historic water right on the Colorado River is not for sale, a top executive with the Colorado subsidiary of Xcel Energy said Monday. Speaking at a meeting of the Colorado Basin Roundtable water-planning group, Jerome Davis, regional vice president of Xcel’s Public Service Company of Colorado, called the plant “extremely important” to Public Service.

The roundtable group is providing input on the state water plan and is hoping that plan takes note of the plant’s importance to western Colorado because of its 1905 water right. The right requires delivery of 1,250 cubic feet per second to the plant and is senior to rights including those of Front Range municipal transmountain diverters. The water continues downstream of the plant because of its nonconsumptive nature.

Western Slope entities have feared that Xcel might sell the small, 15-megawatt plant to a Front Range entity interested in abandoning the water right, which would significantly decrease Colorado River flows certain times of year. There also is Western Slope interest in having an opportunity to buy the plant should it be available for sale, to protect those historic flows.

But Davis on Monday said Xcel isn’t interested in selling the plant. He noted that the company has invested about $21 million there since 2007 repairing a ruptured penstock, doing dam work and a spillway replacement, and undertaking other projects.

“It’s an important plant for us when you talk about system reliability and system stability,” Davis said.

“… It also plays an important role in our renewable portfolio. … Those reasons really drive that in terms of where we view that long-term necessity of that plant.”

He said system reliability and rate competitiveness are Xcel’s top priorities as a utility, and while small, Shoshone adds to that reliability.

The plant doesn’t count as renewable energy in terms of Xcel meeting what’s required of it in that regard in Colorado, but Xcel officials said Monday it’s still viewed as an important renewable source within the company.

Asked whether Xcel would be willing to grant the Western Slope the right of first refusal should it ever decide to sell the plant, Davis declined to make any such commitment. But he did say the company took away that right from Denver in a franchise agreement between the city and Xcel for providing power there.

“We really see no change in terms of our operations” going forward with the plant, Davis reiterated, but he said the company makes a point to listen to all stakeholders and “ensure that all vested interests are listened to and addressed” in whatever it does.

“You’re hearing me say Shoshone is not for sale. I do have a pretty good feel in terms of the importance of it to the entire state,” Davis said.

As part of a 2007 franchise agreement with Denver, Xcel agreed to relax Shoshone’s water call under certain conditions, beginning with a projection that Denver water storage wouldn’t reach 80 percent during spring runoff. He said Xcel worked to involve others in the discussions to reach a balanced agreement that worked for the Western Slope and the river, and Denver proved to be “tremendous partner.”

“There’s this understanding that we work these things out with all stakeholders, as one unit,” Davis said.

A subsequent, far-reaching agreement between the utility Denver Water and dozens of Western Slope entities includes a protocol for generally continuing flows during plant outages, and even if the plant is no longer operational. Under it, the utility also would support possible purchase of a plant by a Western Slope entity. Under that agreement, the Colorado River Water Conservation District has initiated a process to study how best to preserve Shoshone flows, whether through a plant purchase or other means.

Among the concerns for some Western Slope interests is whether Xcel might someday change its mind about selling Shoshone, and the fact that the Denver Water deal doesn’t extend to other Front Range utilities.

Grand County Manager Lurline Underbrink-Curran told Davis Monday that should a time come when the plant is put up for sale, it’s the water right the Western Slope cares about, not Shoshone’s power capability.

“To remove that water right from the West Slope will upset the balance of the state more than you can ever realize,” she said.

Said basin roundtable member Chuck Ogilby, “I just think the Western Slope wants to know that that water right’s going to be there and protect our minimum-flow regime that we have as an assurance today.”

Officials with the river district have indicated they would be a likely interested party should the opportunity to acquire the plant ever arise. But Eric Kuhn, the district’s general manager, said Xcel is the most qualified entity to operate and maintain the aging facility, and that the district’s interest in the plant stems from river flows, not power generation.

“If it were for sale we would have to have somebody who knew the power business as our major partner because we couldn’t do that. We’re not in that business,” he said.

More Colorado River Basin coverage here.


Lincoln Park/Cotter Mill de-commissioning comment period extended

September 1, 2014

From The Pueblo Chieftain:

The U.S. Environmental Protection Agency and state health officials have extended public comment periods on Cotter Corp. Uranium Mill decommissioning documents. Public comments are due by Oct. 27. All documents and addresses for comments to be submitted can be found on the state’s website at http://recycle4colorado.ipower.com/Cotter/docspubcomment.htm.


Getting #energy from oil & gas doesn’t require fresh groundwater

August 27, 2014

Analysis: Thompson Divide waters ‘healthy, uncontaminated’ — Glenwood Springs Post Independent

August 15, 2014
Thompson Creek via the Summit County Citizens Voice

Thompson Creek via the Summit County Citizens Voice

From the Glenwood Springs Post Independent (John Stroud:

A second round of baseline water quality testing within the Thompson Divide region south of Glenwood Springs where natural gas development is proposed finds that two of the major drainages where samples were taken are presently “uncontaminated by any human activities.”

The study, released Thursday by the Thompson Divide Coalition, analyzed both surface and ground water within the Four Mile and Thompson Creek watersheds.

It is in follow-up to the first phase of the study in 2009-10, which produced similar results. Both studies were commissioned by the coalition, which is working to protect the Thompson Divide region from drilling, and were conducted by researchers from the Roaring Fork Conservancy.

Robert Moran, a water quality, hydrogeologic and geochemical specialist with Michael-Moran Associates, worked with the conservancy to analyze the data and is the main author of both reports.

Together, the baseline data contained in the studies should provide a yardstick against any changes in water quality within the two drainages, whether it’s from oil and gas development or other activities, Moran said during a telephone press conference Thursday arranged by Thompson Divide Coalition Executive Director Zane Kessler.

Moran also reiterated one conclusion in his analysis, which is that “some degradation of water quality is inevitable if oil and gas exploration and development becomes a reality within the Four Mile Creek and Thompson Creek watersheds.”

“This should serve as an important reminder that our fisheries and watersheds in the Thompson Divide are at risk,” Kessler said. “These watersheds are the lifeblood of our communities and they deserve to be protected for posterity.”

More Roaring Fork River watershed coverage here.


Many eyes are on Lake Powell and the power pool #ColoradoRiver

August 12, 2014
A high desert thunderstorm lights up the sky behind Glen Canyon Dam -- Photo USBR

A high desert thunderstorm lights up the sky behind Glen Canyon Dam — Photo USBR

Here’s a look at the Lake Powell power pool and the cascading effects if the reservoir drops below the level necessary to continue to deliver power to the southwestern US, from Allen Best writing in The Denver Post:

Colorado water leaders used a curious approach last week in announcing a new water conservation program involving the Colorado River. They talked about electricity and the effect of spiking prices on corn farmers in eastern Colorado, ski area operators on the Western Slope, and cities along the Front Range.

The scenario? A Lake Powell receding to what is called a minimum power pool, leaving too little water to generate electricity. Glen Canyon Dam, which creates the reservoir, is responsible for 81 percent of the power produced by a series of giant dams on the Colorado River and its tributaries, including those on the Gunnison River. This electricity is distributed by the Western Area Power Administration to 5.8 million people in Colorado, Arizona and other states.

Should this power supply be interrupted, WAPA would make good on its contracts with local utilities by buying power in the spot market, such as from gas-fired power plants. But extended drought on the Colorado would certainly increase prices to reflect the higher costs of replacement by other sources.

Hydropower is far cheaper than renewables but also fossil fuels. Rural electrical cooperatives get nearly half the production, followed closely by municipalities, including Colorado Springs, Delta and Sterling, plus Longmont, Loveland, Estes Park and Fort Collins.

Right now, WAPA is selling the energy from Glen Canyon and the other dams at $12.19 per megawatt-hour with a separate charge for transmission. Just how much prices would increase in event of prolonged interruption is speculative. The same agency, however is shoring up August deliveries with purchases of power from other sources at $55 per megawatt-hour, according to Jeffrey W. Ackerman, the Montrose-based manager of WAPA’s Colorado River Supply Project’s Energy Management Office.

This illustrates the bone-on-bone relationship between energy production and water during time of drought.

Yet the broader story about the Colorado River is about a narrowing razor’s edge between supply and demand. There’s no crisis, but water officials are planning for one. A healthy snowpack in Colorado last winter helped, but did not solve problems. The basin as a whole was still below average, as it has been 11 of the last 14 years.

“As leaders, we simply cannot wait for a crisis to happen before we come together to figure out how to address it,” said Jim Lochhead, chief executive of Denver Water. “That would be irresponsible.”

Denver Water and providers in Arizona, Nevada and California, plus the U.S. Bureau of Reclamation, are pooling $11 million to launch a demand-management program. Utilities such as Xcel Energy have similar programs, offering to pay customers willing to suspend use of air conditioners for a couple hours on hot summer afternoons.

In this case, $2.5 million is being allocated to fund programs that would yield reduced demands in Colorado and other states upstream of Lake Powell. The obvious idea is fallowing of crops, such as a hay meadow, with the irrigator to be reimbursed. But Lochhead stresses that it’s a blank chalkboard. The intent is to solicit ideas and then “demonstrate effective demand-management techniques.”

“It’s not something we expect to do. It’s not something we want to do, but if the drought continues, we want to be ready,” says John McClow, Colorado’s representative on the Upper Colorado River Commission.

The bulk of the $11 million will be allocated to demand-management programs in the lower-basin states.

Doug Kenney, director of the Western Water Policy Program at the University of Colorado’s Getches-Wilkinson Center for Natural Resources, Energy and the Environment, sees the agreement as representative of broad shift in states sharing water from the Colorado River. “In the past, they could get together to build things such as dams. Now, they are teaming up to save water,” he says. “That’s a paradigm shift.”

An effort involving The Nature Conservancy and water agencies based in Durango and Glenwood Springs has been underway for five years. That parallel effort, however, is driven by a different trigger: the prospect of a compact curtailment or “call.” The 1922 Colorado River Compact requires Colorado and the other upper-basin states — Wyoming, Utah and New Mexico — to deliver an average 75 million acre-feet over any given 10-year period.

Upper basin states at this point have a cushion of 15 million acre-feet, or two years’ supply. Yet abundant snowfall last year in Colorado only slightly filled Lake Powell. One relatively good year does not compensate for several bad ones.

Always hovering in the background is the prospect of even worse. Tree rings from across the River Basin provide clear evidence of longer, more intense droughts 800 to 900 years ago. An additional layer is the prospect of higher temperatures caused by global warming.

Chris Treese, external affairs director for the Glenwood Springs-based Colorado River Water Conservation District, acknowledges a growing sense of urgency. “We could be back in a near-crisis or crisis situation in as little two or three years,” he says. And for water planners, who typically try to think decades ahead, that’s a current event, he adds. [ed. emphasis mine]

How likely is this dead pool? U.S. Bureau of Reclamation modelers in April found a 4 percent chance of a minimum power pool in 2018 and a 6 percent in 2019. The models are based on recorded hydrology of the last 105 years.

What if Powell does decline and electricity cannot be generated? It depends upon how long the shortage lasts. A longer outage would affect electrical consumers from Arizona to Nebraska. “We’re struggling to quantify the impact,” says Andrew Colismo, government affairs manager for Colorado Springs Utility.

Tri-State is the single largest consumer, purchasing 28 percent of all power produced in 2012 from the dams. It sells this power to 44 member co-operatives in a four-state region, including those who sell to irrigators in eastern Colorado.

Irrigation is a huge consumer of cheap power. In northeastern Colorado, Holyoke-based Highline Electric meets demand that ranges from a low of 25 megawatts to a high of 190 megawatts, the latter occurring when irrigation pumps are drawing water from the Ogallala aquifer to spread across 123-acre circles of corn, beans and other crops. Some large irrigators pay hundreds of thousands of dollars annually in electrical costs, says general manager Mark Farnsworth.

The irony is that if a drought occurs accompanied by heat, as is usually the case, irrigators will probably pump more water and air conditioners will work even harder. Power demands will rise as water levels drop.

Tri-State spokesman Lee Boughey says existing rate structures anticipate both droughts and heavy precipitation.

Lochhead and others also point to other ripples from interrupted power sales. Revenues from hydroelectric sales, which were $198 million last year, are used for a great many programs: selenium control in the Delta-Montrose area, work to maintain ecosystem integrity downstream from Glen Canyon and ongoing efforts to preserve four endangered fish species in the Colorado River and its tributaries.

On Wednesday, Lochhead met with an interim legislative water committee at the Colorado Capitol to report about the new agreement. The testimony all day had been about potential measures to expand water conservation as Colorado tries to figure out how to accommodate a population expected to double from today’s 5.3 million residents to 10 million people by mid-century without drying up rivers and farms.

Denver Water already serves 1.3 million, but gets about half of its water from the Western Slope. “We have a vested interest” in the Colorado River, Lochhead told legislators.

One outstanding question is whether Denver and other water providers on the High Plains should try to be able to get additional water from new or expanded transmountain diversions.

With this story from Lake Powell, the take-home message is don’t count on it.

Allen Best writes frequently for The Post about water and energy and also publishes an online news magazine, found at http://mountaintownnews.net.

More Colorado River Basin coverage here and here.


Huerfano County: Shell fails to convince the Division of Water Resources that produced water is non-tributary

August 9, 2014

coalbedmethanefieldslower48statesviaagiweborg

From The Pueblo Chieftain (Chris Woodka):

An oil company’s claim for underground water near Gardner in Huerfano County was rejected last month by the state.

Shell Oil argued produced water from planned drilling is non-tributary, meaning it could be claimed for other uses. Produced water refers to excess water that nearly always accompanies oil and gas drilling operations.

But the Colorado Division of Water Resources said Shell failed to prove its case, in an initial report. Shell has until Aug. 22 to appeal the finding.

Shell’s consultant, AMEC, failed to consider local geologic factors that connect as well as separate the deep Niobrara shale formation with the natural stream system, according to a decision written by Ralf Topper and Matthew Sares of the hydrogeological services section of the division.

Shell’s application was opposed by Citizens for Huerfano County, a group of about 450 local residents and 600 total members that advocates for clean water and air.

“We’re contending that the water is connected because of the vertical dikes in the particular geology of the area,” said Jeff Briggs, president of the citizens group.

Shell made the claims for water underlying three 25,000-acre tracts known as the Seibert, State and Fortune federal units. It plans to drill 7,000 feet deep with horizontal fracturing at a depth of 5,000 feet.

That plan troubles area residents because of past contamination from drilling, Briggs said.

“We feel the state Legislature and executive branch have tried to facilitate as much oil and gas exploration as possible,” Briggs said. “I think what we are saying is that the decision by all levels of government and the oil and gas industry to go all in on fracking was economic and political and not scientific or medical.”

However the Huerfano County decision might not have statewide implications because it applies to specific geologic conditions found in the Spanish Peaks area.

A nontributary designation has advantages for a driller, because containing produced water for either direct use, treatment or deep injection would not require finding other sources to augment stream depletions

More coalbed methane coverage here.


Geothermal in Pagosa Springs — The Mountain Town News

August 8, 2014


From The Mountain Town News (Allen Best):

Nobody doubts that the Colorado town of Pagosa Springs has hot water. It bubbles to the surface at around 140 degrees and in quantities sufficient to sustain a large commercial spa and several more public pools along the San Juan River.

As well, the hot water heats 13 businesses and 5 homes in downtown Pagosa Springs plus the Archuleta County courthouse, delivering this energy at a cost roughly 20 to 25 percent below the going rate for natural gas and 30 percent less than electricity.

But is there sufficient hot water available to produce electricity, warm 10 acres of greenhouses, and deliver heat to 600 homes?

Geologic modeling suggests there is, but until additional wells are drilled, as is expected later this summer, there’s no way of knowing for sure. If those exploratory wells confirm large volumes of hot water, then two large-bore wells will be required to extract the hot water and, after the heat is transferred from the water, return it underground.

Federal and state grants this year have given the project traction. The U.S. Department of Energy delivered $3.9 million, followed by $1.9 million from state sources. The town and county governments created a consortium called the Pagosa Area Geothermal Water and Power Authority to provide 30 percent in local funds, or $520,000, as required by the federal grant.

A private company, Pagosa Verde, which is pushing the project, came up with an equal amount in in-kind services. It owns 20 percent of the project and has the backing of a South Carolina-based investment firm called Natural Energy LLC.

Another milestone occurred in late May, when Colorado Gov. John Hickenlooper stopped in Pagosa to sign H.B. 14-1222 into law. The law, co-sponsored by Sen. Ellen Roberts, a Republican from Durango, and Sen. Gail Schwartz, a Democrat from Snowmass Village, lengthens the repayment period and otherwise provides great flexibility for private-activity bonds issued with the backing of the state government for geothermal and other renewable energy projects.

Michael McReynolds, policy advisor at the Colorado Energy Office, says the new law recognizes the large costs of proving the geothermal resource exists before development can occur.

However, other areas of the state are interested in replicating the business model of diverse revenue streams being assembled at Pagosa Springs. “It really depends upon the specific communities and what they want to pursue,” he said when asked if the new law will be used to finance other community renewable energy projects.

Jerry Smith, the chief executive at Pagosa Verde, says the new law was “huge” in allowing the project in Pagosa Springs to go forward.

In providing access up to $16.7 million available for as little as 2 percent interest, Smith’s project can now proceed. He estimates the need to spend $26 million before revenue can be gained.

“It’s a community-scale project, replicable throughout the Rocky Mountain states. I wanted town and county citizens to own it,” says Smith. “They only way they could participate was by forming an authority, similar to a housing authority. It’s a quasi-governmental authority.”

The public-private partnership is called Pagosa Waters LLC.

Because of the lower-cost money produced by the state and federal grants plus the clear bonding authority enabled by the new state law, he sees a financial path opening up.

Bonds will be just 2 percent. “That’s essentially free money,” he says. “We can borrow as much as we need to secure revenue for the project, “and it’s a way we go.”

Cheap borrowed money also relieves the onus of finding extremely hot water and arranging for sale of electricity, says Smith. If tests reveal merely hot water, such as bubbles up in the local springs, then that’s still hot enough for greenhouses and living rooms.

From the Romans forward

Hot water originating underground has long been put to practical uses. Romans at Pompei used hot water to heat buildings.

The Idaho Capitol Building has been heated with water drawn from 3,000 feet below ground, but 86 buildings with more than 5.5 million square feet of space are also heated by a separate geothermal heating district, according to Jon Gunnerson, geothermal coordinator for the City of Boise Public Works. It is the largest geothermal heating system in the United States, he says.

Commercial electrical production from geothermal sources began in 1911 in Larderello, Italy. The first commercial electrical production in the United States began in 1960 at The Geysers in California.

In 2013, according to the Geothermal Energy Association, the United States had 3,386 megawatts of installed geothermal capacity, or about three times as much as the trio of giant coal-fired power plants found in the Comanche complex near Pueblo, Colo.

Less prominent than photovoltaic panels, geothermal was nonetheless responsible for 0.41 percent of all electrical generation last year, ahead of solar at 0.23 percent. Biomass, wind, and hydro all produced more than geothermal.

California far and away has the most geothermal installed capacity, followed by Nevada, then trailed more distantly by Hawaii, Utah, and Idaho.

In Colorado, geothermal resources have been used to heat small greenhouses associated with the Mt. Princeton Hot Springs, near Buena Vista, as well as commercial springs. But no electrical production has been achieved because of concerns that new uses will rob existing users of their heat.

“Until very recently, Colorado’s geothermal potential for generating electricity has been assigned little promise,” notes the Colorado School of Mines at its geothermal website. “This appears to be based more on a lack of study, rather than on sound science.”

The website article goes on to note that a 2008 report from the Massachusetts Institute of Technology found that Colorado is the top state in the nation for potential commercial development of its heat, mostly if deep wells are drilled near Rico, Trinidad and other hot spots in a process called enhanced geothermal recovery.

Potential in Pagosa

Just how much electricity the Pagosa project could produce depends upon the heat of water. Colorado School of Mines studies concluded a strong likelihood of substantial hot water 2,000 to 5,000 feet under the land leased by Smith’s company about two miles south of downtown Pagosa Springs. Hot water for the downtown heating district is drawn from a depth of 300 feet.

Smith says it’s a cinch that the water found 2,000 to 5,000 deep will be at least 140 degrees Fahrenheit, the temperature of the water found closer to the surface. If so, it should be enough to produce four megawatts of round-the-clock electricity, what is called base-load generation.

If the water is 250 degrees, as the geological modeling suggests, it could generate 12 megawatts—and still have residual heat for the greenhouses and the homes.

Archuleta County altogether has baseload demand for 20 megawatts of generation. Another renewable source, a proposed biomass plant that would burn forest products to generate electricity, would generate 5 megawatts. Both biomass and geothermal generators probably need to get paid more for their electricity by the local electrical cooperative, La Plata Electric, than what the cooperative currently pays.

Biomass plant proponent J.R. Ford last winter said he needed 15 to 20 percent more than what the La Plata and other electrical cooperatives pay wholesale provider Tri-State Generation and Transmission. Tri-State’s power comes primarily from coal, natural gas, and hydroelectric.

Distributed generation

Both the geothermal and biomass projects in Archuleta County are representative of small sources of electricity called distributed generation. In a famous 1976 essay published in Foreign Affairs, Aspen-area resident Amory Lovins advocated more localized generation as necessary to shift power production from giant but often distant coal-fired power plants. In that same essay, Lovins also stressed that more local sources of electricity would reduce the vulnerability of the grid to terrorism.

“Distributed energy is what the world needs to get to,” says Smith, who cites Lovins as one of his heroes.

Smith moved to Archuleta County in 1989 after a career in the entertainment industry in California. He describes himself as a “liberal arts guy who values things that most people find technical and dry.”

Pagosa Skyrocket via Native Ecosystems

Pagosa Skyrocket via Native Ecosystems

Geothermal is wet, of course, but whether it moves forward in Pagosa Springs depends upon the outcome of a review by the U.S. Fish and Wildlife Service. The 600 acres of land leased for the drilling between the San Juan River and Highway 84 has a plant species, the Pagosa skyrocket (Ipomopsis polyantha), which has been listed as endangered under the Endangered Species Act.

The plant grows one or two feet tall, often in the understory of Ponderosa pine, and has been found in only three places, all near Pagosa Springs.

The federal grant money triggered the need for a biological assessment, which will be the basis for a biological opinion. If adverse effects can be avoided, such as by using care in the placement of wells, the Fish and Wildlife Service can approve the drilling this summer.

Existing wells reach a maximum 1,200 feet, but Smith expects to need wells 2,500 to 5,000 feet deep. The working hypothesis is that the underground rocks at the site are fractured than those that provide the water for the commercial hot springs and downtown heating district.

How will anybody know if the new wells are tapping a new source of heat instead of robbing the existing geothermal resource? Smith says his company will inject heat and pressure gauges on all local hot-water wells, “so they know immediately whether we are tapping the resource.” Colorado law and new regulations in Archuleta County protect existing geothermal users in case of damage to their resource.

Chris Gallegos, who administers the town’s geothermal heating district, says it’s “an unknown” whether Smith’s project would impair the existing users. “Through the test wells we should be able to determine whether the extraction of that heat would affect us or not,” he says.

Additional resources:

http://coloradogeologicalsurvey.org/energy-resources/renewables/geothermal/uses/electrical-generation/

http://www.eesi.org/files/geothermal_030206_gawell.pdf


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