In Modesto, Calif., utility records chart an 18 percent rise in farmers’ energy use in 2014 compared with 2013. No evidence shows exactly why this happened, but California’s drought, now in its fourth year, sent many farmers to their wells to pump from hidden aquifers water that normally would be found at ground level.
Such measures are a timely illustration of the way water needs power — not just to move it, but to clean it and even, with desalination, to create it from brine. A large desalination plant being built to provide 7 percent of San Diego’s water will require about 38 megawatts of power, enough for more than 28,000 homes. And it is no coincidence that primary owners of the 2,250-megawatt, coal-fired Navajo generating station near Page, Ariz., are water managers; they need the power to move water.
The converse is also true: Water is required for power — for hydropower; for extracting oil, natural gas and coal; and, most of all, for cooling power plants. A report from the Congressional Research Service projects that 85 percent of the growth in domestic water consumption from 2005 to 2030 will come from the power sector.
FRISCO —Colorado Attorney General Cynthia Coffman is challenging the federal government’s ability to regulate oil and gas development on federal public lands in the state. In a quiet Friday news dump, Coffman announced her department is suing the federal government over new fracking rules issued in March.
The lawsuit claims the federal rules “invade” the state’s regulatory authority, a similar argument over jurisdiction used by Gov. Hickenlooper and his administration when they sued a local jurisdiction that sought to impose fracking rules in a case that has since been dismissed.
Here’s the release from the Bureau of Reclamation (Patience Hurley):
Reclamation announced today that Great Plains Regional Director Michael J. Ryan signed a Lease of Power Privilege for Granby Dam located near Granby, Colorado.
The LOPP authorizes Northern Water Hydropower Water Activity Enterprise development of a 1.2 megawatt hydropower plant at the base of Granby Dam, a west-slope feature of the Colorado-Big Thompson Project. The project utilizes a “run of dam” design that harnesses water releases from Granby Dam to generate power and provide a clean, renewable source of energy to north-central Colorado.
It will be awhile before the turbines start spinning, but work continues toward installing hydroelectric generation at Pueblo Dam.
An update on the hydropower project was shared by Kevin Meador of the Southeastern Colorado Water Conservancy District staff at this month’s board meeting.
“We’re working with Black Hills Energy on the pricing of power and what we sell it for. That’s a key piece, and we’re getting close to the nitty-gritty,” Meador told the board.
The district is working with Colorado Springs Utilities and the Pueblo Board of Water Works on a 7-megawatt generation system that would be installed at the North Outlet Works on Pueblo Dam.
The structure was built as part of the Southern Delivery System with design allowing for future hydro connection. It would generate about 20,000 megawatt hours annually and could be completed by 2018.
The total cost of the project is in the $20 million range, and so far about $934,000 has been expended in engineering work.
In January, the Pueblo County planning commission issued a finding of no significant impact and the U.S. Bureau of Reclamation decided an environmental assessment would be needed. Black Hills completed an interconnection study in December and recommended hooking up to the grid at a newly constructed substation which will serve the SDS Juniper Pump Station.
More Southeastern Colorado Water Conservancy District coverage here.
The last 50-foot pipe of the 50-mile-long Southern Delivery System arrived at a construction site Wednesday, marking a key milestone for the project as it nears completion next year both on time and under budget.
“We put to rest a lot of doubters that we’d get this done,” said Lionel Rivera, Colorado Springs’ former mayor, who helped approve the project.
With Kool & The Gang’s “Celebration” playing in the background, a truck hauled the massive blue pipe to a site just south of Pikes Peak International Raceway. Crews will place it underground in the coming weeks, completing a system spanning from Pueblo Reservoir to a new water treatment facility in Colorado Springs, which is under construction.
More than 7,000 of the steel, 66-inch-diameter pipes were installed since in 2010. That included a mile-long stretch bored 85 feet below Interstate 25 – a tunnel that was $10 million cheaper than creating a surface trench, according to Colorado Springs Utilities.
Current and former elected officials from across southern Colorado, along with several contractors who have worked on the project, were among scores of people on hand to watch the pipe being delivered. Many signed their names on it.
“It’s great – we’ve been at this a long time,” said John Fredell, the Southern Delivery System’s program director. “It’s a wonderful, wonderful day to celebrate.”
Three pump stations and the treatment facility are expected to be completed this year, with the system up and running for customers in Colorado Springs by the first quarter of 2016, Fredell said.
The project is on track to cost $841 million, below Colorado Springs City Council’s approved budget of $880 million in 2009, which did not account for inflation or rising material costs. The council also serves as Utilities’ board. Those savings rise to about $150 million when factoring in the cost of inflation and increases in material costs, said Fredell, who credited design changes to the pipeline and water treatment facility for much of the savings.
One of the biggest water projects in the western U.S. will hit a major milestone this month, when the last piece of 50 miles of pipe is laid for the Southern Delivery System, the $841 million project to bring new water supplies to Colorado Springs and nearby communities.
The project includes 50 miles of pipeline, three pump stations and a water treatment plant. It will deliver water from the Pueblo Reservoir to Colorado Springs, Fountain, Security and Pueblo West.
More than 7,000 sections of blue-colored, welded, steel pipe 50 feet long and most of it 66 inches in diameter were installed on the project during the last 3 1/2 years of construction.
The project spent $204 million on pipe and installation, according to the Colorado Springs Utilities.
“The pipe is the main artery for this water project and we are extremely pleased with how the pipeline construction went,” said John Fredell, the program director for the Southern Delivery System project.
The project is in the final year of construction and Fredell said the costs are expected to be nearly $150 million under the original budget…
Northwest Pipe (Nasdaq: NWPX), based in Vancouver, Washington, manufactured the SDS pipe at its Denver plant.
Three contractors installed the pipe, Garney Construction, headquartered in Kansas City with an office in Littleton; ASI/HCP Contractors of Pueblo West; and the heavy civil division of Layne, a construction firm based in The Woodlands, Texas, which has four offices in Colorado.
Construction is continuing on other elements of the Southern Delivery System project, including a $125-million water treatment plant and pump station that will have the capacity to treat and pump 50 million gallons of water per day. Three pump stations will help move water uphill, about 1,500 feet in elevation, from the Pueblo Reservoir, also are under construction.
Construction on the remaining portions of the project are expected to be finished by the end of 2015.
Community leaders gathered Wednesday to celebrate the completion of pipeline construction for the Southern Delivery System (SDS). The project consists of more than 7,000 50-foot sections of steel pipe that have been installed over the last three and a half years. The pipe will transport water stored in the Pueblo Reservoir north to Pueblo West, Fountain, Security and Colorado Springs.
“It’s taken many years and it’s taken many city councils and it’s taken many leaders and many workers to accomplish this,” said Colorado Springs City Councilman Merv Bennett. “Our friends to the south, the Lord gave them the Arkansas River as their delivery system. To the north, Denver has the South Platte River as their delivery system. We have Fountain Creek and we ran out of that water in 1912.”
Proponents of the SDS argue the pipeline will ensure Colorado Springs and surrounding areas can continue to grow, especially toward eastern El Paso County. The region will have to worry less about drought and watering restrictions.
“Water is important. It’s the lifeline of a community,” said Lionel Rivera, former mayor of Colorado Springs. “It’s the way you grow and I think we’ve ensured the water supply for at least the next 50 years.”
Rivera was mayor from 2003 until 2011 and helped get the project rolling. He said Tuesday that it was one of the most rewarding things he did as mayor.
“It’s very exciting, a little bit emotional to see that pipe,” Rivera said. “It just made me think of all the stuff we had to go through to get this approved. We were told back when we started it that it couldn’t get done from a political standpoint, but we proved the doubters wrong.”
The project has had opponents over the years, many from Pueblo who are concerned over stormwater issues.
Though pipeline construction is complete, workers still need to build water treatment plants and pump stations. The first drop of water is expected to be delivered in spring 2016.
Construction crews are poised to lay the final pipeline link for Colorado’s biggest water project in decades — an $841 million uphill diversion from the Arkansas River to enable population growth in Colorado Springs and other semi-arid Front Range cities.
Eleven 2,000-plus horsepower pumps driven by coal-fired power plants will propel the water from a reservoir near Pueblo through a 50-mile pipeline with an elevation gain of 1,500 feet.
This is the first phase, moving up to 50 million gallons a day, for a Southern Delivery System that utility officials estimated will eventually cost $1.5 billion.
“It means we will have greater water security,” Colorado Springs utilities spokeswoman Janet Rummel said. “Businesses need water. Our communities need water to survive. It means we can continue to serve our population as it grows.”
Water challenges loom across Colorado, with state officials projecting a 163 billion-gallon shortfall. A few years ago, drought forced Colorado Springs to stop watering municipal parkways and gardens.
The diverted water can be used only within the Arkansas River Basin, officials said, ruling out sales to south Denver suburbs. And the river water, after treatment, must be returned to downstream farmers.
Colorado Springs residents have been paying for the project through water bills, which increased by 52 percent over four years. Utility officials spent $475 million from bonds.
The water will flow by next March, officials said. At full buildout, the system will store water in two new reservoirs east of Colorado Springs.
The Southern Delivery System pipeline’s completion was marked by a contingent of El Paso County officials and a smattering of Pueblo County folks as well.
For John Bowen, president of ASI Constructors of Pueblo West, the SDS project has meant bread on the table as well as water in the pipes.
“It’s generated $50 million in contract values for our company,” Bowen said during a ceremony to mark completion of the SDS pipeline from Pueblo Dam to Colorado Springs. “We were able to grow as a business during a time when a lot of contractors were laying people off.”
ASI was the primary contractor for the connection at Pueblo Dam, as well as 12 miles of the 50-mile SDS pipeline route, and relied on 70 local businesses for support services. The SDS project generated $800,000 in wages for ASI workers.
More Southern Delivery System coverage here and here.
State and federal incentives together producing new power from old dams
As with most smaller dams from that era, no hydroelectric turbines were installed in Pueblo Dam when it was constructed during the early 1970s. It’s located in central Colorado, the silvery summit of Pikes Peak in the distance, impounding the Arkansas River as it meanders onto the Great Plains.
The dam’s 191 feet height provides what hydrologists call head, a prerequisite for making large amounts of electricity. Absent, though, are large volumes of water.
Now, with strong financial and other incentives from both the state and federal governments, dam operator Southeastern Colorado Water Conservancy District seeks to install turbines sufficient to allow production of 7 megawatts.
Five such retrofits in the West have occurred since 2008. Pueblo and 18 others are in the pipeline. Many are in Colorado, which has emerged as a model for how to encourage the retrofitting of smaller, older dams.
Retrofitting Colorado dams and canals
Ridgway Reservoir (8 MW): completed 2014
Carter Lake (2.6 MW): completed 2013
South Canal Drops 1 and 3 (7.5 MW): completed 2013
Lake Granby (1.2 MW): underway
Pueblo Reservoir (7 MW): underway
Shavano Falls (2.8 MW): underway
South Canal Drop 2 (1 MW): underway
Michael Pulskamp, who oversees the U.S. Bureau of Reclamation’s lease-of-power-privileges program from an office in suburban Denver, says the 2005 Energy Bill required resource assessments of federal water infrastructure but the Obama administration delivered the push.
Those studies found great cumulative potential. A 2011 study concluded that one million megawatts of annual production of electricity could be delivered if just the 70 most promising dams, diversion structures, and tunnels were developed. The study had screened 530 federal sites.
Colorado, Utah, Montana, Texas, and Arizona have the most sites with hydropower potential.
“That study really laid out that we weren’t tapped out in terms of hydropower potential,” says Pulskamp.
Another federal assessment of 373 irrigation canals, tunnels, and other conduits in 13 Western states found another potential 103.6 megawatts of generating capacity.
Even if all the 1.1 million potential megawatts identified in the two studies get built, the capacity will be dwarfed by existing dams in the West. Grand Coulee Dam, completed on the Columbia River in 1941, produces 21.5 million megawatts annually, tops in the West. Glen Canyon Dam, on the Colorado River, can produce 3.8 million megawatts, followed closely by Hoover Dam with 3.7 million.
Shasta Dam, in California, can produce 1.9 million megawatts and Davis Dam, on the Colorado River in Arizona, produces 1.1 million megawatts.
Colorado’s largest hydroelectric production comes from the three dams on the Gunnison River in what is called the Aspinall Unit. Together, they can produce 826,000 megawatts annually. Hydroelectric capacity installed in several components of the Colorado Big-Thompson diversion project can collectively produce 413,000 megawatts.
In comparison, new turbines on Utah’s Jordanelle Dam can produce 39,000 megawatts annually while Colorado’s Ridgway Dam, which went on line last May, can produce 22,000 megawatts annually.
Pueblo will produce even less, 19,700 megawatts annually. Southeastern Water was prodded into taking on the project only after the Bureau of Reclamation specifically solicited proposals.
“We were afraid if we didn’t pursue it, a private entity might come and develop the project,” says Kevin Meador, project manager for Southeastern Colorado Water. The Pueblo-based agency administers water diverted to the Arkansas from the Aspen area under federal sponsorship in the Fryingpan-Arkansas Project.
Colorado’s state government has provided both financial incentives and a market for sale of renewable energy. One of the incentives is a 2 percent loan at 30 percent from the Colorado Water Conservation Board. “That is a huge factor in making this project feasible,” says Meador.
In setting a 30 percent renewable portfolio standard for investor-owned utilities and now a 20 percent standard for Tri-State Generating & Transmission, Colorado has created a market for power from smaller dams. No buyers for the electricity from Pueblo have been lined up, but Meador says his agency needs to get 3.5 to 4 cents per kilowatt hour to make the numbers work.
If this were Massachusetts or Hawaii, where electricity prices to consumers run up to 25 cents per kilowatt hour, that would be an easy sell. But in the Rocky Mountains, energy has historically been relatively cheap, observes Meador, “and these hydro projects are capital intensive. They are very expensive up front.”
Seven percent of all U.S. electricity comes from hydropower. In Colorado, it’s 4 percent. Pulskamp says that the greatest hydroelectric potential lies in further harnessing the slow-moving but vast quantities of water in the Mississippi River and its tributaries. His agency, however, has little oversight there.
Kurt Johnson, president of the Colorado Small Hydro Association, says Colorado could serve as a model for other states. He points to efforts begun in the administration of former Gov. Bill Ritter to surmount an often clunky, discouraging federal permitting process. Even more important, Colorado has sweetened incentives with low-cost, long-term loans. Finally, last year it lowered regulatory hurdles.
Two key federal laws passed by Congress in 2013 simplified the federal regulatory process. One law specifically targeted Bureau of Reclamation facilities. Johnson’s organization now seeks to lower the hurdle for other existing but non-federal facilities that must get approval from the Federal Energy Regulatory Commission.
Despite the recent growth, however, hydroelectric remains just a small part of new electrical generating capacity, both in the West and nationally. In 2015, gas was responsible for the most new generating capacity, followed by wind and solar. Hydro was just 1 percent of total national production.
Yet even with just trickles of water, hydro power now makes sense financially. Consider Granby Dam, which plugs the Colorado River a few dozen miles from the river’s origins in Rocky Mountain National Park. The dam is 298 feet tall, providing plenty of head. Like Pueblo, it lacks water: just 20 cubic feet per second of water gets released during winter months, as required for environmental purposes, and 75 cfs during summer, except in the biggest of runoff years. The rest gets diverted to cities and farms east of the Continental Divide.
With so little water, Granby can generate just 1/800th of the total production of Hoover Dam. That small production, along with competition from cheap power, is why turbines were never installed when the dam was built from 1941 to 1950.
“Probably power sale rates were next to nothing,” says Carl Brouwer, a project manager for Northern Water, the water agency that distributes Colorado-Big Thompson water to the Boulder-Greeley-Fort Collins area.
As with Pueblo, Northern Water had first shot at obtaining the lease to produce power and did so to preclude shared operations. Northern was aware of at least one other bidder, says Brouwer.
Granby also needed the state’s $5.1 million loan at 2 percent interest is crucial in moving the $5.8 million project forward. “That low-interest loan is what makes this project feasible,” says Brouwer.
A smaller revenue stream comes from sale of the environmental attributes of the energy through a financial device called renewable energy certificates, or RECs. Purchaser was Tri-State Generation & Transmission.
Annual revenues, projected to be $375,000, will pay off debt and operations during the first 30 years. But unlike coal-fired power plants, the supply of fuel will always be free.
Here’s the release from the Colorado Oil and Gas Conservation Commission (Todd Hartman):
The Colorado Oil and Gas Conservation Commission today [March 2] unanimously approved new rules that outline requirements for operators with facilities located within floodplains.
The new rules implement several of the recommendations contained in the Commission’s “Lessons Learned” report published in March 2014 following the Front Range floods of September 2013.
The nine-member Commission approved regulations designed to better protect oil and gas facilities that may be subject to flooding and that require more preparations from operators to reduce potential impacts. The new rules formalize “best management practices” when operating within a floodplain and require:
All tanks, new and existing, be surrounded with hardened berms made of steel instead of earthen barriers.
Critical equipment be anchored according to an engineered anchoring plan.
The removal of existing pits used for exploration and product waste.
All new wells to be configured so operators can shut the well in remotely.
“We learned a great deal from our experiences in September of 2013, including what existing practices were successful in reducing damages,” said Matt Lepore, director of the Commission. “Requiring these practices for oil and gas operations within a floodplain makes sense and will ensure environmental impacts are reduced and equipment is further protected should we see another flood event.”
In addition, the new rules require operators, by April 1, 2016, to establish an inventory of wells and critical equipment located within a floodplain and to register all such wells and equipment with the COGCC. Operators are also required to create a formal plan on how they will respond to a potential flood.
“These new rules requiring operators to establish an inventory and a formal response plan will help ensure both operators and the COGCC can react more quickly when a flood threatens or strikes,” Lepore said.
These new rules are effective June 1, 2015 for new wells and equipment and April 1, 2016 for retrofitting of existing equipment.
The new floodplain rules is the latest of numerous steps undertaken by the COGCC to improve regulation of oil and gas development in Colorado and part of Governor Hickenlooper’s commitment to long-term recovery and resiliency after the 2013 floods.
Since 2011, the Hickenlooper administration has crafted rules to increase setbacks, reduce nuisance impacts, protect groundwater, cut emissions, disclose hydraulic fracturing chemicals, increase spill reporting and significantly elevate penalties for operators violating Commission rules.
The Commission has also significantly expanded oversight staff, intensified collaboration with local governments, sponsored ongoing studies to increase understanding of impacts to air and water, streamlined its process for public complaints, increased public access to COGCC data and adopted several formal policies to address health and safety issues brought about by new technologies and increased energy development in Colorado.