Headwaters Fall 2013: Energy

C o l o r a d o F o u n d at i o n f o r W at e r E d u c at i o n | Fa l l 2 0 1 3

The Energy Issue Colorado’s Shifting Energy Mix The Risks and Rewards of Oil and Gas Drilling Power and Energy in the Water Market Water = Cooling + Hydropower

Headwaters | Fall 2013

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Colorado Foundation for Water Education

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CFWE Mission in Motion Growing Capacity

Cultivating Participation

Colorado’s Water Plan MillerCoors Support and Happy Hour CFWE is thrilled to announce a new partnership with MillerCoors beginning in late 2013. We will kick off the “Watershed Happy Hour” series at the Golden Brewery later this year. MillerCoors will host a gathering of their employees and other CFWE supporters to honor our work, strengthen relationships and toast water stewardship with a Colorado-made brew! MillerCoors’ generous financial support will go a long way towards helping all Coloradans “speak fluent water.” Thank you!

Colorado has arrived at an unprecedented point in water history, one where dialogue and consensus among water leaders is leading to a comprehensive plan to address our state’s water challenges. CFWE is proud to support understanding of Colorado’s Water Plan and the Basin Implementation Plans through our facilitation of the Public Education, Participation and Outreach workgroup of the Interbasin Compact Committee. To further support participation in a secure water future, expect to see additional activities from CFWE over the coming year, including: 3 Special communications pieces representing a diversity of perspectives on channels such as the “Your Water Colorado” blog and “Connecting the Drops” radio series 3 Relevant speakers and topics at CFWE programs and events, such as Headwaters magazine receptions and our annual Legislative Lunch 3 Cross-promotions of CWCB communications and social media Read more about Colorado’s Water Plan and sign up for regular updates at www.coloradowaterplan.com.

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Correction to Headwaters Summer 2013 Story The article, “The Rio Grande Compact,” which appeared in the Summer 2013 issue of Headwaters on page 18, misstated the impact to Colorado’s Rio Grande Compact apportionment that could be wrought by critical habitat designation for the southwestern willow flycatcher in New Mexico. Although some worry critical habitat designation could change Colorado’s water delivery requirements to New Mexico, the U.S. Fish and Wildlife Service says that it cannot use the designation to require the delivery of more water downstream. If any extra water is required, or changes in delivery made, it will be under the terms of the compact.

Find additional coverage on this topic online at blog.yourwatercolorado.org.

Welcome New Staff CFWE continues to grow and change in order to best meet the water education needs of Colorado. We are happy to welcome Alicia Prescott as our new Development Director.

Alicia moved to Colorado in July with her husband and two dogs, and started at CFWE in September. She’s ready and excited to continue her development career in Colorado water! Previously, Alicia has worked in university fundraising, campaign development, grant writing, special event planning, and volunteer management across the American South. She graduated from the University of Southern Mississippi with a bachelor’s degree in marketing and a master’s in business administration. Please help us welcome Alicia to CFWE and Colorado by buying her a sweet tea when you meet her!

Alicia Prescott

Strengthening Leadership

Water Educator Network We’re making water education better and easier! CFWE’s all-new Water Educator Network is bringing you tools, training and resources to increase the amount and quality of water education in Colorado. Through this network, with generous support from Xcel Energy, CFWE will improve the understanding of Colorado water issues within youth and adult audiences by becoming the premiere resource for Colorado water educators to learn, share and connect with each other. There’s a lot to look forward to. Be sure to grab the next issue of Headwaters magazine, hitting mailboxes in January 2014—the entire issue will focus on water education and civic engagement. What better way to launch a new network? Stay tuned to yourwatercolorado.org for upcoming trainings, meetings, resources and more.

Headwaters | Fall 2013

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CFWE Mission in Motion Creating Knowledge

Increasing Awareness

Connecting the Drops CFWE is on the air, bringing you quality reporting on the radio and the web. We’ve partnered with community radio stations from Greeley to Durango to create regular water programming for the next year, with the potential of reaching hundreds of thousands of listeners across Colorado. Tune in for monthly segments that complement and build on what you’re reading in Headwaters. And visit yourwatercolorado.org to access archived stories from our radio spot: “Connecting the Drops.”

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The Great Citizen’s Guide Giveaway For a limited time, nonprofits and educational groups can receive up to 100 free CFWE Citizen’s Guides! The Citizen’s Guides are a series of high-quality reference booklets on Colorado water topics. Educate your staff, volunteers, board, students and constituents, and boost their understanding of Colorado’s water resources. To be considered, you must submit an outreach plan by November 22. Learn more at yourwatercolorado. org or by contacting CFWE intern Abby Kuranz: akuranz@gmail.com.

Colorado Foundation for Water Education

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yourwatercolorado.org

Colorado Foundation for Water Education Board Members Gregg Ten Eyck President Justice Gregory J. Hobbs, Jr. Vice President Rita Crumpton Past President Eric Hecox Secretary Alan Matlosz Treasurer Becky Brooks Nick Colglazier Lindsay Cox Lisa Darling Steve Fearn Rep. Randy Fischer Greg Johnson Pete Kasper Dan Luecke Trina McGuire-Collier Kate McIntire Kaylee Moore Reed Morris Sen. Gail Schwartz Andrew Todd Chris Treese Reagan Waskom

Staff Nicole Seltzer Executive Director Kristin Maharg Program Manager Caitlin Coleman Program Associate Jennie Geurts Administrative Assistant Alicia Prescott Development Director

“I feel so old. It’s great!”

You don’t often hear people in their 30s and 40s rejoicing in their maturity, but at the 2013 Sustaining Colorado’s Watersheds Conference in October I heard it numerous times. The Colorado Foundation for Water Education is proud to be a partner in this annual event that draws a large number of college students, budding water professionals and nonprofit volunteers. It is gratifying to sit in a room full of young energy, hearing them challenge their assumptions, promote their good work and learn from those who are now (hopefully) a bit wiser than they were 10 or 20 years ago. And I had more fun than I should have dressed up as “Captain Cutthroat” thanks to the Roaring Fork Conservancy. (Check out photos on CFWE’s Facebook page.)

From a more diverse and enthusiastic audience showing up at traditionally staid water meetings to the numerous phone calls and emails CFWE gets asking how to help with our work, I see widespread evidence of a burgeoning interest in water. I am grateful for this attention, and my hope is that the professional water community can find ways to welcome and embrace it.

In my opinion, Colorado is more than halfway through its transition from what author George Sibley, in a 2009 article for Headwaters magazine, called an “adversarial and litigious ‘every man, or city, for himself’ culture” to a more democratic process where diverse interests sit at the same table and come to mutually beneficial agreements. The difficulty I see, however, is what exactly the role of “the public” is in managing and protecting water in Colorado, given the importance of honoring private property rights. As those young conference attendees become the leaders of tomorNicole Seltzer row, they will have a chance to wrestle with this question, and I look forward to where their vision will take us.

But as I look forward, I also need to remember to look back. This Headwaters is the last of 2013, a year of tremendous change for me personally, for CFWE and for the state of Colorado. Having recently traded my long commute for a house in Denver, I am now a bona fide “city girl.” I get to wear my high heels more often, but I do miss the rural landscape of northern Boulder County. I drove by my old house in Longmont yesterday for the first time since the September floods and marveled at the changes in the St. Vrain River.

My thoughts are with those who are dealing with tremendous personal loss, and those who are working tirelessly to fix the ruined transportation, energy and water systems our communities rely upon.

At the Foundation, we continue to make great progress toward our goal of helping all Coloradans “speak fluent water.” In the past year, we increased staffing levels by bringing Caitlin Coleman on fulltime and hiring our first Development Director. This additional staff capacity has allowed us to broaden our reach and try some new things, such as the “Connecting the Drops” monthly radio series. We’re also hosting our first energy-focused tour in the Weld County area on Nov. 8. Join us if you are able!

I am excited by the direction we are moving at CFWE, and am gratified by the moral and financial support we continue to get from you, our supporters. In 2014, look for more new programming including professional development support for water educators funded by Xcel Energy.

Finally, I hope you and your loved ones have a safe and happy holiday season (which apparently is already in full swing if you judge by the seasonal aisle at Target). May 2014 bring you happiness and lots of snow!

Executive Director Want to share your support of Headwaters with over 10,000 readers each edition? Call Alicia at 303-377-4433 for sponsorship and advertising opportunities!

Mission Statement The mission of the Colorado Foundation for Water Education is to promote better understanding of water resources through education and information. The Foundation does not take an advocacy position on any water issue.

Acknowledgments The Colorado Foundation for Water Education thanks the people and organizations who provided review, comment and assistance in the development of this issue.

1580 Logan St., Suite 410, Denver, CO 80203 303-377-4433 • www.yourwatercolorado.org

Headwaters Magazine is published three times a year by the Colorado Foundation for Water Education. Headwaters is designed to provide Colorado citizens with balanced and accurate information on a variety of subjects related to water resources. Copyright 2013 by the Colorado Foundation for Water Education. ISSN: 1546-0584 Edited by Jayla Poppleton. Designed by Emmett Jordan.

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Contents Fall 2013

Water is…

7 Cooling Water converted into steam to turn turbines must be cooled back to its liquid state; When it comes to water use and efficiency, cooling technologies vary; Options for cooling solar plants.

8 Hydropower Hydropower ranks low for overall electricity generation, but its contribution is growing; Reducing hydro’s impact on rivers; The power potential of small projects.

Emmett Jordan (2), Kevin Moloney (power plant), Blue Water Resources (canal), Richard Stenzil (Pueblo Reservoir)

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The Power (and Energy) of Water

Do Oil and Water Mix?

Power in the Marketplace

By Joshua Zaffos The state’s energy portfolio is in transition, which may yield water-saving gains, even as the state braces for a growing population and the forecasted impacts of more persistent drought.

By Allen Best Oil and gas production in Colorado is at near-record highs, with no signs of slowing. But public concerns are growing and the jury’s still out on the safety of practices such as hydraulic fracturing. How will the state balance development with adequate protections?

By Caitlin Coleman From leasing water rights to diversifying water supply portfolios, both power providers and energy companies are in the market for water. The demand has contributed to higher prices—and some creative arrangements.

Contributors Allen Best has written about oil and gas issues in Colorado since 2008, and about water issues for decades. He grew up in the South Platte Valley, where it was his family’s eternal hope that oil would be found on his grandparents’ farms, though it never happened. His work has appeared in publications as diverse as High Country News, Telluride Watch, Colorado Biz Magazine and The New York Times, among others. He publishes Mountain Town News, which can be found at mountaintownnews.net.

Joshua Zaffos writes from Fort Collins, where he also teaches journalism and natural resources communications at Colorado State University. His stories have been published by High Country News, Wired, Scientific American, Nature Conservancy Magazine, and many other outlets. His work is online at joshuazaffos.com.

Caitlin Coleman is a writer and program associate for the Colorado Foundation for Water Education. Originally from New York State, writing about water for energy, a prominent but often polarizing topic country-wide, was enlightening, she says.

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Matthew Staver is an independent documentary and commercial photographer based in Denver. Every project is different, but his approach is constant: creating visual permanence in a world of relentless motion. His work can be found at matthewstaver.com.

Kevin Moloney is a Colorado native and freelance photojournalist who has covered the western energy boom since 1996 for the New York Times and other publications throughout Europe and the United States. He is a frequent contributor to Headwaters. His work can be found at kevinmoloney.photoshelter.com.

Charles Chamberlin is a freelance graphic designer living in Boulder. Some examples of his work can be found online at cdcgraphics.blogspot.com.

On the Cover: The Ft. Saint Vrain Generating Station, owned by Xcel Energy, lights up the sky near Platteville, Colo. Once Colorado’s only nuclear facility, it was decommissioned in 1989 and re-powered as a natural gas plant. Photo by Kevin Moloney.

Colorado Foundation for Water Education

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yourwatercolorado.org

Ten Jayla Poppleton, Editor

Surely it came as a surprise to many when it was reported by the U.S. Energy In-

formation Association early in October that the United States is poised to eclipse Russia and Saudi Arabia for oil and gas production by the end of the year. Fueling the domestic boom in production is the ability to tap oil and gas from shale deposits where it was previously uneconomical to recover.

Hydraulic fracturing, or fracking, is the technology that has received most of the hype, both for the bountiful production it has enabled, as well as for the controversy it has sparked among wary citizens concerned about air and water quality and other disturbances.

In Colorado, one of the top-10-producing states for both oil and gas, the center of activity has closed in on populated areas in the northern Front Range, further heightening residents’ alarm. Now there’s plenty of NIMBYism (Not In My Back Yard) to go around, and I can’t say I blame people.

September’s floods on the Front Range and associated oil spills magnified the fact that despite our precautions, accidents happen, with consequences we have yet to fully realize. And still there is the unignorable fact that we are a society heavily reliant on the resource being provided. Increased oil independence could also arguably improve national security and smooth tensions abroad.

Dialogue over safety issues in the public arena has been obscured by the lack of consistency in language. Often, when the public refers to concerns about hydraulic fracturing, they’re roping in the entire process of well development, whereas industry and regulators narrow the definition to the underground fracturing “treatment” of the shale formation. For the dialogue to be effective, we all need to get on the same page. In this issue, we attempt to clear up some of the misunderstandings.

From a water availability standpoint, concerns have been raised about the amount of water required in the fracking process. Yet the numbers are miniscule when looking at the big picture in Colorado: Only 0.04 percent of the water removed from streams and aquifers is used for fracking.

But when that demand is focused in a few targeted locales where oil and gas development is concentrated, the local impacts become more significant.

The argument is similar when it comes to power generation. Of course a reliable power supply is integral to our day-to-day lives, and we certainly want to make sure our power suppliers are adequately stocked with the water they’ll need to keep our power lines humming. But it’s difficult to make the case that statewide water requirements for power generation are a mighty strain on the resource in the midst of the much, much larger demands stemming from agriculture and municipal use. Still, in the face of population growth and escalating water demands from every sector, every drop counts. Hence the advantage of water-saving technologies and fuel choices when it comes to generating power.

Join us in exploring the dual topics of energy development and power production in this issue.

As with all Colorado water matters, it’s important to consider and address the concerns of all Coloradans. Here’s to a bright future in Colorado,

n Jayla Poppleto Editor

Things To Do In This Issue:

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Tune in to the “Connecting the Drops” radio program for additional coverage on water and energy issues (page 2).

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Get a crash course in technologies used for cooling steam at power plants (page 7).

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Stay current on trends in hydropower development in Colorado (page 9).

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Calculate how your energy use measures up via the National Geographic personal energy meter (page 15).

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Learn which counties are Colorado’s hot spots for oil and gas production (page 17).

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Trace water’s path through the process of hydraulic fracturing, oil and gas recovery and waste fluid disposal (page 20).

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Search the Colorado Oil and Gas Conservation Commission’s database for information on wells drilled in your area (page 22).

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See how much water is used to power the average home in Colorado (page 29).

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Find out how different types of power factor into Colorado’s energy mix (page 14).

Sign up to receive updates on Colorado’s Water Plan (page 1).

P.S. Remember to look for our “Floo-uhnt” water facts, and get a leg up in your ability to “speak fluent water.” We also encourage you to jump on the opportunities we’ve provided to “Take the Next Step” in your water education journey, highlighted throughout this issue.

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Cooling > Hydropower

Water

is

Colorado

Photo by John Wark The 1,426-megawatt Comanche Generating Station sits southeast of Pueblo, where its three coal-fired generating units produce more power than any other plant in Colorado. Operational since 1973, the plant added a second unit in 1975 and a third in 2010. The third unit is the most efficient coal plant in the state, producing more power with less fuel. It also employs a hybrid system that uses ambient air temperature to aid cooling, reducing the plant’s water use by half.

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Colorado Foundation for Water Education

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yourwatercolorado.org

Water is Cooling

Water Fuels Power

In Colorado, less than 0.5 percent of water tapped from rivers and aquifers is used for power generation. It seems insignificant, but here’s a look at water’s crucial role in Colorado’s power play. —Rebecca L. Olgeirson When it comes to power generation, the reliance on fossil fuels and resulting air quality issues generally garners the most attention.

However, here in arid Colorado it’s also important to understand how water fits into the power picture.

Thermoelectric power relies on heating water to create steam and then using that steam to spin turbines. The spinning turbines generate electricity. This part of the process is the same across all types of thermoelectric power plants. What varies is the type of fuel used to heat the water—coal, natural gas, nuclear, concentrating solar, even geothermal or biomass—and the water cooling method employed.

The water heated in the power generation process must be cooled in order to condense it from a vapor state back to liquid form before it can be

reused by the plant or returned to its source.

Water resource issues such as drought, water rights and water quality regulation all factor into power generation, as they affect water availability and plant operation. As a result, industry representatives say they weigh the costs and benefits of different technologies’ water usage carefully. Still, decisions aren’t made in a vacuum. Often less water-intensive cooling technologies are also less efficient, requiring more fuel for the same amount of energy produced, increasing fossil fuel reliance.

“Upstream” water demands related to fuel choice impact overall water use as well. Coal, for example, which supplies 67 percent of Colorado’s electricity, requires 20 to 60 gallons per megawatt hour of electricity produced before it ever gets to the power plant, according to the

Wonder what makes water such an effective cooling agent? Attributed to the strength of their hydrogen bonds, water molecules have a very high specific heat compared to other substances, meaning they are capable of absorbing large quantities of heat with only a slight change in their own temperature.

U.S. Department of Energy. This water is used for mining, washing and transporting the coal.

Developing natural gas requires 30 gallons per megawatt hour if hydraulic fracturing is used, or 5 gallons for conventional drilling. Natural gas currently supplies 20 percent of the state’s electricity.

Stacy Tellinghuisen, senior energy/water policy analyst at Western Resource Advocates, says Colorado’s energy sector is more water conscious than other parts of the nation. But given water scarcity and future drought issues, the power sector’s water needs must continue to be considered in decisionmaking. “Looking forward, with Colorado’s growing population and climate change, we need to keep in mind water demands as we make energy choices: ‘Are the water supplies there? Are we allowing flexibility in how we use water in the future?’”

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Technology Keeps it Cool Water use in Colorado is tallied in two ways—withdrawal and consumption.

Withdrawal is how much a water user removes from a water source, some of it temporarily. And consumption is the amount of water “permanently” removed from the system, some of which evaporates into the atmosphere only to rain down somewhere else.

When it comes to generating power in Colorado, most plants consume the vast majority of the water they withdraw—90 percent on average. By comparison, agriculture, which withdraws nearly 200 times as much water as the state’s power plants, is 43 percent consumptive on average, according to Colorado’s Division of Water Resources.

Operating in an environment of relative water scarcity, Colorado power

plant operators have developed cooling systems accordingly. Of the three main types—once-through systems, closed-loop systems and dry-cooled systems—Colorado power providers rarely use once-through systems due to their higher water demand.

Once-through systems, which cycle cooling water through only one time, withdraw the most water from natural sources, but consume less because most of the water used for cooling is later returned to the water source. Discharge temperatures, regulated on a per-plant basis by the Colorado Water Quality Control Division, must be low enough to protect fish and the environment, although they can still raise water temperatures by as much as 25 degrees Fahrenheit.

Continued on page 8

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Water is Cooling

Keeping it Cool Continued from page 7 Closed-loop or recirculating systems, which use water to cool steam back into a liquid state before returning it to the steam cycle, withdraw less water but have a 70 to 80 percent consumption rate in Colorado, according to Xcel Energy. These are the most common systems employed here. These systems move water from the steam cycle through pipes called cooling towers, where a large volume of cool water falls over the tower, lowering the temperature of the water within before cycling it back into the system.

According to Jordan Macknick, environmental analyst at the National Renewable Energy Laboratory (NREL) in Golden, once-through cooling technologies withdraw 10 to 100 times more water per unit of power generation than cooling tower technologies, yet cooling tower technologies can consume twice as much water as oncethrough systems.

Finally, dry-cooled systems use no water, but rely on tremendous volumes of air current and require more energy to operate, trading lower water use for increased fuel consumption. These systems are also quite expensive to build and depend on ambient air temperature for efficiency—working great on cold days, less so in the heat of summer or in the desert. However, some facilities, including an Xcel plant in Pueblo, have installed hybrid systems that utilize water for cooling only when air temperatures are too high for dry cooling. Xcel says its new hybrid system cuts water consumption by 50 percent.—Rebecca L. Olgeirson

Water for Solar When talking solar, most people think of the thin, black panels sitting on a rooftop or in a field. This type of photovoltaic (PV) solar collector requires very little water.

But there’s another kind of solar energy, and a wide chasm separates it from its cousin when considering water use. Concentrating solar power (CSP) consists of massive installations of mirrors that direct sunlight to one spot, where it heats a working fluid into the steam used to produce electricity, just as at a conventional power plant.

The big difference? CSP plants do it without fossil fuels.

If outfitted with a typical closed-loop, recirculating water tower cooling system, however, CSP plants consume between 725 and 1100 gallons of water per megawatt hour of electricity produced, according to a recent report by the National Renewable Energy Laboratory. CSP plants require water for washing the mirrors, but most of their water usage is attributed to cooling, the same as at a conventionally powered plant.

An added concern is site location—the best sites for CSP plants are often in desert-like conditions where water is already scarce. As a result, most new CSP plants proposed in dry regions would be dry-cooled, despite the higher cost and reduced efficiency rate of the waterless technology.

—Rebecca L. Olgeirson

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Water is Hydropower

Hydropower In 2010, Colorado produced more than one and a half million megawatt hours of electricity using hydropower. While this accounted for less than 4 percent of total electrical generation in the state, technological advances and streamlined regulations are improving the outlook for adding more of this energy source to Colorado’s power mix.

Colorado has more than 60 hydropower units collectively capable of producing 1,160 megawatts of power at any given time. One quarter of that installed capacity comes from three dams on the upper Gunnison River—the Crystal, Morrow Point and Blue Mesa dams of the Aspinall Unit, which collectively produce up to 288 megawatts. These dams were constructed in the early 1960s to store water for the upper Colorado River Basin; adding hydropower became an incidental purpose, says Bureau of Reclamation hydrologist Dan Crabtree. Today, that power—enough to supply as many as 100,000 homes—is sold to municipalities, public utilities and governmental agencies in Colorado and surrounding states through the Western Area Power Administration.

Large facilities like the Aspinall Unit are unlikely to be built today, however. “Ecological damage basically restricts development of large-scale hydropower, especially on mainstem rivers,” says Crabtree.

New projects are much smaller—and take advantage of existing infrastructure. Reclamation currently has several new hydropower projects underway in Colorado: The Dallas Creek Project on Ridgway Dam on the Uncompahgre River and the South Canal Hydroelectric Project downstream near Montrose will each generate close to 8 megawatts, together providing enough electricity to power more than 5,000 homes annually. Affordable construction loans and power purchase agreements with Aspen and Tri-State Generation and Transmission made the projects feasible.

Typical impediments to hydropower development include expensive start-up costs, although hydropower has a longer economic life and costs less to maintain and operate than other renewable energies, says Brad Florentin, senior engineer with AMEC, a consulting firm that works on energy projects worldwide.

Acquiring power purchase agreements can also be difficult, as well as securing necessary permits—but that recently became easier with the passage of two bills signed into law by President Obama in August 2013. The Hydropower Regulatory Efficiency Act, introduced by Colorado Rep. Diana DeGette, and the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act, introduced by Colorado Rep. Scott Tipton, should shorten regulatory timeframes, as well as expedite small hydropower development at existing Reclamation-owned canals, pipelines, aqueducts and other waterways. Moving more quickly than many expected, the Federal Energy Regulatory Commission approved its first application, for a project in Idaho, under the new legislation in October 2013—a promising sign to small hydro advocates.

In 2011, Reclamation identified 37 additional sites where hydro facilities could be installed on existing dams in Colorado. Tapping those resources could generate another 242,000 megawatt hours of electricity per year, says Reclamation’s senior advisor for hydropower Kerry McCalman. In 2012, the agency identified an additional 28 sites on the state’s irrigation canals with the potential for generating 100,000 megawatt hours annually. Together, the retrofits could supply 40,000 homes.

Still, Colorado hydropower will never compare to a state like Washington, whose Grand Coulee Dam on the Columbia River alone produces more than 10 times the amount of hydropower of all that is generated here—Colorado streamflows simply can’t compete with such a massive river. —Sharon Sullivan Built in 1981 as part of the Fryingpan-Arkansas Project, the Mt. Elbert Power Plant near Leadville is capable of producing 200 megawatts of electricity. This pumped-storage hydro plant helps meet peak power demands by pumping water uphill from Twin Lakes Reservoir during times when demand is low, then releasing it to drop through the plant’s turbines when demand is high.

Water is Hydropower

in Colorado Reducing Hydro’s Impact Hydropower accounts for nearly two-thirds of all renewable energy generation in the nation, according to the U.S. Department of Energy. Generally considered a “clean” energy source because there is no fuel combustion and little air pollution compared with generating energy using fossil fuels, hydropower facilities still have their drawbacks.

Large dams, for example, have significantly impacted rivers by altering their flow patterns, in some cases virtually wiping out native species. Under natural conditions, high springtime flows inundate floodplains, providing both nursery areas and quiet water habitat for adult fish prior to spawning, says Patty Gelatt of the U.S. Fish and Wildlife Service Western Colorado Field Office.

In 2010, Reclamation began implementing new operating strategies for its 288-megawatt Aspinall Unit to help endangered fish and critical habitat, in-

creasing water releases in the spring to mimic the river’s natural seasonal flow, though such efforts have come at a cost to total power generation.

Fish, which need well-oxygenated water, can also be impacted by the oxygen-reducing effect turbines have on flowing water. Oxygen is restored naturally when water flows over rapids, or ripples. In some cases, engineering structures are installed in rivers to replicate that re-aeration effect. Other mitigation efforts include fish passages and ladders to help migrating fish navigate over dams and electronic fish barriers to prevent fish from swimming into areas where they risk being struck by turbines.

To be considered, and certified, “low-impact” by the Low Impact Hydropower Institute, projects must meet criteria for minimizing these types of impacts. Such certification, the institute notes, could be a selling point for marketing power from hydro projects. —Sharon Sullivan

Big Potential for Small Hydro

Courtesy Telluride Energy

Although the days of building new, large-scale hydropower projects are likely limited, possibilities abound in Colorado to install power-producing turbines on existing infrastructure. Such “micro-hydro” technology captures the energy of water moving through the state’s irrigation and municipal systems, often in order to power on-site operations.

The Colorado Department of Agriculture has hired Applegate Group, a Colorado-based engineering and consulting firm, “to create a roadmap for the Department to successfully support the development of small agricultural hydropower,” says Applegate water resources engineer Lindsay George. One notable success is a project on the Wenschhof cattle ranch in Meeker, where Applegate assisted with securing funding, permitting, construction and commissioning of a 23-kilowatt hydropower system that provides for all of the ranch’s electrical needs—at a projected savings of $350,000 in utility costs over 30 years.

Applegate also worked with the Colorado Energy Office on the recently published Colorado Small Hydropower Handbook. The handbook is a resource for utilities, farmers and ranchers, and others interested in developing the resource, focusing on projects of 2 megawatts or less. Good prospective sites for adding small hydropower are characterized by existing infrastructure, such as dams and pipelines, consistent water flows, and at least 15 to 20 feet of “head,” or water level difference, says George.

Grand Junction is one municipality that has utilized the technology, developing micro-hydropower at its Kannah Creek Water Treatment Plant a few years ago. Utilities manager Terry Franklin helped design a 30-kilowatt system that generates enough electricity to run the facility, saving $8,000 a year in energy costs. Payback for the $50,000 project was just over six years. —Sharon Sullivan

The Towoac-Highline Canal delivers irrigation water to the Ute Mountain Ute Tribe near Cortez, capturing 360 kilowatts of power as it passes the Carver Drop.

Colorado’s renewable energy targets exclude existing large hydropower projects of more than 30 megawatts from qualifying as renewable, as well as new projects, coming online after 2005, of greater than 10 megawatts.

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Power (AND Energy) OF Water

THE

Jonathan Waterman/Lighthawk

by Joshua Zaffos

The Cherokee Generating Station along the South Platte River in Denver uses water recycled from the adjacent Metro Wastewater treatment plant (foreground).

For five decades, the Cherokee Generating Station, on the north side of Denver, ran on western Colorado coal and cheaply powered the population boom of Colorado’s Front Range. Its four coalfired, steam-electric generating units produced up to 717 megawatts, enough electricity for more than half a million homes. The plant—one of the largest operated by Xcel Energy in the state—also emitted many thousands of tons of pollutants annually, including nitrogen oxides, sulfur dioxides and carbon dioxide, contributing to poor air quality, smog and climate change. As for water, Cherokee was more innovative. The plant requires up to 10 million gallons or 30 acre feet per day to operate, but its water supply for years has been recycled wastewater from the same households purchasing its power.

Cherokee may embody the good, the bad and the ugly of energy development and power generation, but for the last two years, this cornerstone Colorado power facility has been undergoing a $530 million makeover to replace coal with more efficient natural gas. Xcel has al10

ready demolished Cherokee’s two oldest coal-fired units, and will shutter another by 2015. In their place, construction is now underway on a new 569-megawatt natural gas-fired, combined-cycle plant, which uses gas and steam turbines to run on fuel as well as waste heat that would otherwise be lost as exhaust. The last 352-megawatt coal-fired unit will be converted to run on natural gas by 2017.

The retrofit is the keystone of Colorado’s strategy to slash Front Range air pollution, including reducing smog-causing ozone levels by 86 percent. The 2010 Clean Air-Clean Jobs Act, signed into law by thenGovernor Bill Ritter, serves as a roadmap to bring the state into compliance with federal air quality standards by phasing out older coal-fired power plants and replacing them with more efficient and less polluting gas-fired facilities and renewable energy. The law also helps Colorado prepare for anticipated federal greenhouse gas regulations to address climate change.

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This shift is providing another important environmental advantage.

“The retirement of coal plants and the movement toward natural gas is an important step [for addressing air pollution and carbon emissions], but the side effect is water use reduction,” says Kristen Averyt, director of the Western Water Assessment and associate director for science at the Cooperative Institute for Research in Environmental Sciences (CIRES) at University of Colorado Boulder. Planned nationwide retirements of coal plants, generating 51,000 megawatts, will eliminate 4 trillion gallons, or more than 12 million acre feet, in water withdrawals annually.

That’s even after replacing them with more water-efficient power stations, according to a July 2013 report by the Union of Concerned Scientists. “[The reduced water use] is not intentional, but it’s a co-benefit, and I think that’s important to think about,” says Averyt.

With Colorado’s—and the nation’s—energy portfolio in transition, the intersection of water and energy is becoming less of an after-

thought. From underground coal seams to sky-high wind currents, planners and policymakers are increasingly evaluating energy sources based on their water use and looking at how their choices can help address growth, climate change and other issues. And with its full menu of energy options, Colorado is “ground zero,” Averyt says, for testing the local impacts of national energy policies and influencing how the country powers its future.

Revamping the Energy Mix Few states rival Colorado when it comes to energy resources. Impressive reserves of oil, gas and coal underlie parts of every corner of the state. Rivers and dams provide hydroelectricity on large and small scales. Uranium deposits in Paradox Valley and elsewhere could fuel nuclear plants. With 300 days of sunshine, solar energy potential abounds, and the eastern plains, where gusts can blow a lofty average of 20 miles

Headwaters | Fall 2013

11

per hour, are ideal for wind energy. Geothermal heat beneath the San Luis Valley and other areas holds energy potential too.

Colorado has relied on coal as its dominant power source since settlement due to local abundance, including wide-ranging deposits across the Western Slope, which makes it an especially affordable fuel. Coal powered more than 90 percent of the state’s net electricity generation as recently as 1995. Today, about half of U.S. electricity generation comes from coal, while Colorado relies on the fossil fuel for 67 percent of its power.

During the 1990s and early 2000s, as Colorado’s population swelled from 3.3 million to 5 million, federal air quality violations and concerns about pollutants from existing and new coal power kicked off a discussion on the state’s energy mix. In 2004, voters approved Amendment 37, establishing a renewable energy portfolio standard that mandated utilities tap renewable energy sources for 10 percent of their power by 2015.

Since Amendment 37 passed, the state legislature has revised the target renewable standard several times, most recently in June 2013.

Now investor-owned utilities, of which Xcel is the largest in the state, are required to provide 30 percent of electricity from renewable sources by 2020, one of the highest benchmarks in the nation. Under the same timeline, city utilities must move to 10 percent renewables, and large rural electric cooperatives will have to reach 20 percent—a percentage doubled under the 2013 legislation. Many rural providers believe reaching that target in seven years is going to be incredibly difficult, if not impossible—in part due to the need for new transmission lines to connect renewable sources in their far-flung service areas.

And yet, the statewide proliferation of pho-

Water Withdrawals in Colorado 0.80% Large Industry

• 86% Agriculture • 8% Municipal • 2.5% Recreation & Fisheries • 1.5% Industrial/Commercial • 1% Augmentation • 1% Recharge

0.45% Thermoelectric Power Generation 0.07% Commercial

0.04% Hydraulic Fracturing 0.03% Solar, Coal, Natural Gas & Uranium Development 0.03% Snowmaking

Source: Colorado Division of Water Resources Cumulative Yearly Statistics 1996-2008

tovoltaic solar panels and wind turbines is evidence of the change underway. Solar power systems now generate 270 megawatts of electricity in Colorado, although Environment Colorado and industry trade group Colorado Solar Energy Industries Association want to boost that total to 3,000 megawatts by 2030.

So far, solar development has relied heavily on tax credits, exemptions and rebates from federal, state and local government and utilities in order to be price-competitive with coal or gas power. But installation costs for solar projects here have been decreasing, a promising sign of improving pricing equality with other energy sources.

Wind energy has developed even faster, with

2,300 installed megawatts of capacity as of late 2012. Ten years ago, Xcel supplied less than one percent of its electricity from wind energy, says Jack Ihle, the company’s director of environmental policy. Today, Xcel’s figure is 17 percent and growing, accounting for most of the state’s wind energy resources. As with solar, the federal renewable electricity production tax credit subsidizes wind, geothermal and biomass energy development to achieve competitive prices with fossil fuels. The increasing affordability and efficiency of wind turbines have also contributed to wind power prices nearing all-time lows in 2012, according to an August 2013 report by the U.S. Department of Energy’s Lawrence Berkeley National Laboratory.

There are 65 electric and natural gas utilities serving Colorado: 51 provide electricity only, eight provide only gas, and the remaining six provide both. The large number is, in part, a legacy of the 1936 Rural Electrification Act, which accounted for Colorado’s large size and required service to more remote, rural locations. Source: Colorado Governor’s Energy Office

PROVIDING

ENERGY

MIX with a

DIVERSE ENERGY.

There are a variety of sources from which we generate your energy—coal, natural gas, wind, solar and hydro power. A diverse mix makes your energy more affordable, reliable and cleaner.

Discover your energy mix at xcelenergy.com

xcelenergy.com

© 2013 Xcel Energy Inc.

12

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Colorado’s utilities are meeting renewable goals, says Joshua Epel, chair of the state’s Public Utilities Commission. “No one else is doing anything else like Colorado, in terms of its renewable portfolio standard and Clean AirClean Jobs.” In addition to solar and wind development, Epel points to recent initiatives to capture and use methane from coal mines and to process and burn forest waste for bioenergy as promising test programs. “The strategies adopted have tremendous potential to propel Colorado forward,” Epel says.

While the Clean Air-Clean Jobs Act is spurring the reduction of coal power, the shift is also fueled by the natural gas boom. The advancement of horizontal drilling technology and hydraulic fracturing—used to obtain oil and gas from once-unobtainable deposits—have skyrocketed gas production around Colorado, the United States and the world.

The surge in hydraulic fracturing, or fracking, and gas drilling has lowered prices and made it a much more cost-effective fuel for power, Ihle says. Under Clean Air-Clean Jobs, Xcel plans to reduce its coal energy output from 69 to 45 percent of its total fuel mix by 2018, while ramping up gas energy from 17 to 35 percent. To pay for its Cherokee project, Xcel estimates rates for its customers will rise by just 2 percent.

Tri-State Generation and Transmission, a co-op which serves 44 smaller providers, says coal is still a more affordable fuel choice for its rural customers. Referencing a 2013 report by the American Coalition for Clean Coal Electricity, Tri-State’s water resources policy advisor Laura Chartrand says, “Striving for affordability is especially important to the 907,000 Colorado households earning less than $50,000 per year who devote an estimated 19 percent of their after-tax income to energy.”

Annual Water Consumption Acre Feet Per Year

Plant Name 1

Craig

2

Comanche

8,200

3

Cherokee

6,300

4

Hayden

5,900

5

Pawnee

5,700

6

Rawhide

3,700

7

Fort St Vrain

3,000

8

Rocky Mountain Energy

2,900

9

Ray D Nixon

2,800

10

Martin Drake

2,700

11

Valmont

1,900

12

Front Range Power Plant

1,300

13

Arapahoe

1,000

14

Nucla

800

15

W N Clark

400

16

Colorado Energy Nations

300

17

Lamar Plant

200

18

TCP 272

200

19

Williams Ignacio

100

20

Arapahoe Combustion

100

21

Brush Generation Facility

Although nothing is currently slated for Colorado, nuclear power could factor into energy planning as a low-carbon source of electricity on par with the cost of power generation using other fuels. The Fort St. Vrain Generating Station in Weld County was Colorado’s only nuclear facility, but it was shut down in 1989 and is now operated

by Xcel as a gas-fired plant. Few people support siting a nuclear plant near communities, based on fears of spills and meltdowns, and reactors are very costly to build. Nuclear power, including uranium processing and production, is also extremely water-intensive, requiring more water per megawatt-hour than fossil fuels. But technological breakthroughs, such as the use of treated sewage water at Arizona’s Palo Verde nuclear plant—the country’s largest nuclear facility—are already changing how planners and some members of the public view nuclear energy.

Even with the rush toward natural gas, the push for renewables, and potential carbon emissions regulations, Ihle says Xcel—and Colorado—aren’t likely to fully divest from coal. Xcel is upgrading pollution controls at several coal plants to further limit smog and air pollution and keep the plants running and in compliance with Clean Air Act regulations.

“We see value in balance even as certain drivers like emissions regulations will cause us to look harder at cleaner resources,” Ihle says.

“Coal has been a very cost-effective resource and price-stable for a long time, and we’ll look for ways to make it as clean as we can.”

The utility also supports developing carbon capture and storage technologies to produce fewer and less harmful emissions. Carbon capture has its own water use implications, however: According to Averyt, the technology presently requires twice as much water as coal power without carbon capture.

100 64,200

The Energy/Water Nexus In the last decade, the nationwide economic recession has slowed Colorado’s population growth rate, while drought across the state has elevated the challenges facing utilities and resource managers. Looking ahead to 2040, state demographers and other planners forecast a more gradual 1.5 percent growth rate for Colorado. That’s still above the national average and equivalent to 80,000 or more new citizens each year who will want reliable and affordable electricity—and a beautiful place to live.

While improved air quality has driven energy policies, water conservation continues to get increasing attention from energy researchers and planners.

The “energy-water nexus” defines the mutual relationship between the two resources, with the acknowledgment that each affects the other’s availability. Water is essential to developing and generating energy, and energy is essential to supplying and treating drinking water and wastewater. In the western United States, water providers are among the largest users of electricity, while power plants require a significant quantity of water to operate.

According to the Colorado Division of Water Resources, the state’s power plants withdraw 64,500 acre feet of water annually—and consume 90 percent of that. That’s enough

Water Use by Power Plant

16,400

TOTAL

One megawatt (the same

as 1,000 kilowatts) of electricity

capacity can supply about

800 average homes in the United States or as many as 1,000 average Colorado homes. As of 2011, Colorado ranked 34th in the nation in energy consumption on a per capita basis. Source: U.S. Department of Energy

1

Heat Source

6 4

18

7

11

3 20

16

5

21

Coal

Denver

13

Grand Junction

10 15

14

8

9 12

Colorado Springs

Natural Gas

Pueblo

2

17

Other

Durango 19 Colorado’s major power plants are strategically located near water sources and, with a few exceptions, near population centers to reduce transmission losses. Note: Circle sizes are based on estimated water consumption. Facilities consuming less than 100 acre feet per year are tallied but not shown. Source: Western Resource Advocates 2012 Data Sources: U.S. Energy Information Administration, National Renewable Energy Laboratory Headwaters | Fall 2013

13

Matthew Staver Jordan Macknick surrounds himself in solar research equipment at an NREL lab, where he studies the lifecycle water needs of different power sources.

water to meet the needs of more than 350,000 people, although in exchange, these plants generate more than 87 percent of the electricity used in Colorado.

Natural gas plants, which are replacing most of the lost coal-powered megawatts, use less water and are more efficient. Based on research from the National Renewable Energy Laboratory (NREL), a new coal plant consumes about 500 gallons per megawatt hour (MWh) produced, while a combined cycle gas plant consumes about 200 gallons per MWh. Combined cycle gas plants also convert 50 percent of energy to electricity, while the efficiency rate of coal stations is closer to 33 percent.

That’s not to say the process of obtaining natural gas through drilling and hydraulic fracturing doesn’t require its share of water, but according to Jordan Macknick, energy and environmental analyst for NREL, who has analyzed different power sources’ water consumption across their entire “life cycle,” the oil and gas industry’s water use is mostly “up front” during the extraction process, compared with coal power, which requires water continually for mining, transporting and processing over the life of the mine.

Fracking’s water consumption has still been a major point of criticism from opponents. Depending on the depth and location of a well, an operator may use from 2 million to over 5 million gallons—1 million gallons is about 3 acre feet—of water to initially drill and frack a site, a volume significantly greater than that used for conventional drilling. The process also typically contaminates

most of the water, rendering it unsuitable for future use, although more and more operations are testing and implementing treatment technologies that allow them to reuse and recycle water, which could provide benefits financially—and to surface flows and groundwater.

It’s all about tradeoffs, concludes Macknick.

More gas-fired power will save water at the generation stations, but it does come with impacts on the ground at the shale plays where natural gas is extracted.

Water use also ranges across low-carbon and renewable energy sources. Wind power is unarguably the most “water-smart” alternative, consuming a relatively negligible amount for operations and little else for its “fuel” procurement or power production. Photovoltaic solar panels also use a minimal amount of water to make power, but manufacturing equipment requires some water. Concentrated solar power, which uses mirrors or lenses to beam sunlight to run a heat engine, usually a steam turbine, can require more water than coal plants to cool facilities, depending on the type of technology employed.

Low water-use cooling technologies at power plants also provide a way to conserve water.

Dry cooling systems, for example, use air instead of water to cool the steam that passes through turbines, reducing a power facility’s water consumption by more than 90 percent compared with closed-loop, wet cooling processes. However, the technology has its tradeoffs: Dry cooling has higher capital costs than the alternatives and lower efficiency. A gas

Colorado Power Generation by Source, 2010 THERMOELECTRIC

COAL CAPACITY

Megawatts: WATER INTENSITY

Gallons/MWh: Cost/MWh:* GENERATION

2010 MWh:

5,702 480 $123

Median Water Consumption

34,559,000

Considerations: Reliable, affordable,

highest emissions; new technologies such as carbon capture and storage can shave emissions, but may increase water intensity.

68.1%

Of Total Power Produced in Colorado

THERMOELECTRIC

WIND

NATURAL GAS CAPACITY

Megawatts: WATER INTENSITY

Gallons/MWh: Cost/MWh:* GENERATION

2010 MWh:

5,325 200 $66

CAPACITY

Megawatts:

Median Water Consumption

WATER INTENSITY

Gallons/MWh: Cost/MWh:*

11,062,000

Considerations: Price volatility in past, but may be stabilizing; initial investment required if converting from coal plant; lower emissions than coal but not without impacts to air quality and warming.

21.8%

Of Total Power Produced in Colorado

GENERATION

2010 MWh:

1,294 0 $87 3,555,000

Considerations: Requires consistent wind.

American Wind Energy Association reports 2,301 MW capacity as of 2012.

6.8%

Of Total Power Produced in Colorado

*Costs are projected national averages (in 2011 dollars), levelized to include construction and ongoing operation costs for new facilities coming online in 2018. Regional variations in fuel availability and operational costs could have significant impacts on prices.The U.S. Energy Information Administration reports that a 3-percentage point increase in the cost of capital was added to coal power without carbon capture and storage, accounting for possible future requirements to purchase allowances to offset their emissions.

14

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wer

plant with a dry system may need to burn more fuel to produce the same amount of electricity as a facility with wet cooling, while a solar plant would be producing less power with a dry versus wet system.

“Low carbon isn’t always low water,” says Averyt, “but it can be depending on the choices you make.” Water conservation isn’t driving the rapid development of Colorado wind energy, but the savings are exactly the sort of unintentional byproduct that she identifies in energy policies.

Accounting for Water Moments of energy-water nexus serendipity aside, planners and analysts now recognize that water management and drought planning should become a more integrated element of energy policy.

“Most of our clean energy policies have not been driven by water issues,” says Stacy Tellinghuisen, Western Resource Advocates senior energy/water policy analyst, “but I think as we see long-term drought affecting the Colorado River Basin and the region more broadly, we’re likely to see water issues become a bigger factor in shaping our energy policy in the future.”

The threat of drought and climate change impacts lingers over Colorado. Climate models project summer temperatures will warm 2.5 degrees Fahrenheit by 2025 and 4 degrees by 2050. While precipitation shifts are less certain, a report from the Western Water Assessment and the Colorado Water Conservation Board points to a reduced water supply in the state by 2050 and more severe

and persistent drought conditions.

Colorado officials are working on a state water plan and climate action plan, both of which, leaders say, will address the linked relationship between energy and water. In the absence of national climate legislation, the state’s Clean Air-Clean Jobs Act also serves as preemptive action on climate change.

“Colorado is probably the leader in reducing greenhouse gas emissions on a per-capita basis,” says Epel, the Public Utilities Commission chairman.

“I think we’re on the right track, and Colorado is a leader in the region in terms of how they’re beginning to integrate water into energy decisions,” Tellinghuisen adds. But she says more is possible, such as managing energy supplies to be more resilient to drought.

Analysts, including Averyt and Macknick, working with Union of Concerned Scientists recently compiled a report, “Water-Smart Power,” highlighting risks and opportunities facing energy and water providers. Among the report’s conclusions: Our current strategy of replacing coal with natural gas as the dominant power source will reduce water withdrawals for power by more than 80 percent and water consumption for power by more than 40 percent—but much of those savings won’t occur until after 2030 because of rising demands from population growth and the continued use of fossil fuels over the next few decades.

Regarding climate, replacing coal-fired power with natural gas production has already contributed to lower carbon emissions from electricity

generation, according to data from the U.S. Energy Information Administration (EIA). The Environmental Protection Agency figures gas-fired electricity emits only 40 percent of equivalent carbon dioxide compared with coal, even accounting for methane leakage and other factors.

But despite the efficiency gains and water savings associated with gas-fired power, computer models performed by the “Water-Smart Power” report’s authors and data from the EIA suggest using gas to supply 60 percent of U.S. power needs would minimally reduce the power sector’s carbon emissions in the long-term, especially as energy demands grow.

While there remains cause for concern, there is also reason for hope. Xcel and other utilities now consider the environment along with reliability and affordability in making decisions. Goals for renewable and alternative energy production are being met in Colorado.

And even if energy policies don’t yet directly incorporate water planning here, the nexus is never far off in people’s minds.

“In the West, water is always a fundamental part of the equation in every decision that is made,” says Averyt. “It’s built into our thinking.” q

Estimate your carbon footprint

and find out how your

energy consumption measures up

with National Geographic’s Personal Energy Meter. Find it by visiting www. nationalgeographic.com and searching for “Personal Energy Meter.”

Capacity (in megawatts—MW) represents the highest production capability at any given moment if facilities are running at full bore.

Generation (in megawatt hours—MWh) represents the power produced over time, and is affected by outages or weather variability.

HYDRO CAPACITY

Megawatts: WATER INTENSITY

Gallons/MWh: Cost/MWh:* GENERATION

2010 MWh:

1,225 0 $90

CAPACITY

WATER INTENSITY

Gallons/MWh: Cost/MWh:*

Considerations: Larger projects can negatively impact rivers; evaporative water losses on reservoirs built specifically for hydro raise water intensity; new hydro projects are trending smaller and built on existing infrastructure.

3.1%

BIOMASS Megawatts:

1,578,000

Of Total Power Produced in Colorad

PHOTOVOLTAIC

GENERATION

2010 MWh:

13 640 $111

CAPACITY

Megawatts:

Median Water Consumption

WATER INTENSITY

Gallons/MWh: Cost/MWh:* GENERATION

60,000

2010 MWh:

Considerations: Water requirements vary depending on whether biomass is captured waste, such as wood waste or landfill gas, or a byproduct of producing fuel such as ethanol, where the fuel originates as irrigated crops.

0.12%

SOLAR

Of Total Power Produced in Colorado

41 0 $144 42,000

Considerations: Concentrated solar can have higher water intensity than coal; areas with greatest potential lack existing transmission. Environment Colorado reports 270 MW capacity as of 2012.

0.08%

Of Total Power Produced in Colorado

Sources: U.S. Energy Information Administration, National Renewable Energy Laboratory

Headwaters | Fall 2013

15

Do Oil and Water Mix?

by Allen Best

Technology has produced a bonanza of oil and gas. But many want assurances that

Emmett Jordan

water resources are not being harmed.

Three drilling rigs operate in close proximity to each other east of Greeley in unincorporated Weld County.

16

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Whatever you may think about oil and gas drilling, acknowledge this much: The technology is jaw-dropping. A decade ago, library shelves were sagging with books foretelling declined production of oil and natural gas. Guess what? In July 2013, the International Energy Agency announced that the United States will become the world’s leading producer of natural gas in 2015 and the world’s leading producer of oil in 2017.

The technology driving increased production isn’t altogether new. Hydraulic fracturing was first used in Colorado in 1948. The application of water, sand and chemicals at high pressures to stimulate production is called by the industry and regulators a “frac.” To journalists, that spelling looks unkempt, so the news outlets call it a “frack.” To opponents, it’s a four-letter word no matter how you spell it. What’s different between those original fracks and those currently done an average of five times every day in Colorado is like the chasm between the first Apple computers and MacBooks today: the new versions are immensely more powerful—and more precise. Instead of pumping fluids by the thousands of gallons, as the first fracturing jobs did, today

companies commonly use more than 5 million gallons of water to “shoot” deep rock layers and fracture them. Tiny fissures smaller than a follicle of hair are formed and propped open by sand particles and other “proppants,” allowing the oil and gas to escape out of the rock and into well casings. Fracturing chemicals, which constitute less than 1 percent of hydraulic fracturing fluid’s total volume, are used to improve effectiveness.

Many are ordinary, benign household or industrial substances, but some are known carcinogens and other toxins, raising concern about potential impacts to water quality.

The industry has proclaimed fracturing fluids safe for their intended use—thousands of feet underground—and Gov. John Hickenlooper in

2011 even sipped on a glass of Halliburton’s new “green” frack fluid, called CleanStim, as if it were a scotch and water. Not everybody’s buying such assurances. If it’s so safe, say opponents, why have companies for so long resisted disclosing the contents? The industry says it’s about maintaining that competitive edge; who can provide the most effective frack? In Colorado, but not all states, both chemicals and their relative proportions as a percentage of total fluids injected during fracking are a matter of public record since 2012. Recipes for specific ingredients, however, remain private under laws that protect intellectual property.

Horizontal drilling has also enabled drillers to more efficiently extract the hydrocarbon residue of organic matter in ancient sands, muds and other sedimentary rock. It’s down, down you go, to 3,000, 5,000 and even 10,000 feet, and then slowly hook to the left or right into the unconventional deposits, so-called because they are so much more tightly compressed and cemented, the spaces between particles not even half as large as those of previous, or more conventional formations containing “reservoirs” of oil and gas. Another key technological gain is 3-D seismic imaging, which allows exploration teams to better visualize oil and natural gas prospects, place wells more effectively,

2012 Colorado Oil & Gas Production Value By County (Millions of Dollars) None < $1 million

$1 - $10 million $10 - $100 million $100 - $1,000 million > $1 billion

Sedgwick Moffat

Jackson

$81.7

Routt

$9.9

$4.6 Rio Blanco

Morgan

$25.5

Broomfield

$19.6

Denver

Garfield

Jefferson

$2,246.2

$2.3

Weld

Adams

Washington

$50.7

$3.2

Cheyenne

$0

$116.5

$19.8

San Miguel

Bent

$16

$0.8 Huerfano

$21.6

Garfield

La Plata

Kiowa

Fremont

$17.4

Prowers

$2.9

Sources: Colorado Oil and Gas Conservation Commission, Natural Gas Intelligence, U.S. Federal Reserve Economic Data

$37.1

Montezuma

$308.6

Kit Carson

$0.7

Lincoln

$38.8

Delta

Dolores

Natural Gas

$95.3

$47.6

Elbert

Mesa

$5.2

Oil

$11.2

$0.1

Gunnison

Ratio of oil to natural gas production in Colorado's three leading counties

Yuma

Arapahoe

$135.3 $0.2

Phillips

$6.9

$13

Boulder

$655.2

$21.1

$3,997.2

$16

$0.2

Logan

Weld

Larimer

La Plata

$1,000.7

Las Animas

Archuleta

$271.3

Baca

$8.7

$37.2

Headwaters | Fall 2013

17

In November 2012, 60 percent of Longmont voters enacted a ban on hydraulic fracturing within municipal borders, triggering a legal battle yet to be resolved. In effect, those voters—and others who have contemplated similar bans up and down the Front Range—find existing state regulations inadequate, the risks to property values, public health and water supplies still too unclear.

In Colorado, federal, state and local governments all have a say in regulating oil and gas activities, and about in that order. The broadest, most powerful laws governing water quality come from the federal government. Clean Water Act standards set by the U.S. Environmental Protection Agency specify how much water produced by coalbed methane wells, for example, must be cleaned—and to what extent—before being released into creeks and rivers. EPA rules also govern the injection of “exploration and production” waste fluids into disposal wells under the Safe Drinking Water Act. In practice, much of the authority is delegated to two state agencies, the Colorado Department of Public Health and Environment and the Colorado Oil and Gas Conservation Commission (COGCC).

The degree of authority held by local governments to regulate aspects of oil and gas drilling varies, but must fall under the umbrella of local land use regulations. Longmont, a home-rule city, recently asserted its authority to impose stricter limits than those set by the state in the siting of oil and gas wells and certain procedures related to hydraulic fracturing. A June 2012 city council ordinance—enacted prior to the citizen-initiated fracking ban—more than doubled setback distances required by the state at the time, prohibited surface access for drilling at public parks and sports fields, and restricted oil and gas operations and facilities in zoned residential districts. It also required disclosure of ingredients in hydraulic fracturing fluids at an earlier point in the process than what is required by the COGCC. Now Colorado is pushing back, saying the city has overstepped its legal authority and citing a regulatory patchwork that could result from such local actions.

“Conflicts such as those with Longmont and [the COGCC] arise because the lines between ‘land use’ and the technical aspects of drilling that [the COGCC] regulates, are not always easy to discern,” says Matt Lepore, director of the COGCC. Barbara Green, a Denver-based lawyer whose practice involves environmental issues and local government authority, expects the city of Longmont’s position to be upheld by the courts, though certain provisions could be struck down categorically. In previous cases, she says, courts have found that challengers must prove that regulations “materially impede or destroy the state’s interest” before they would be invalidated. But uncharted ground is the citizen-initiated ban on fracking, currently being challenged by the Colorado Oil and Gas Association. There is no precedent involving a ban of one particular method of oil and gas extraction. “If the ban is upheld, it will certainly pave the way for more bans. If the ban is not upheld, then the implication is that there must be different approaches to resolving concerns about the public health and safety of fracking other than prohibiting it,” says Green.

–Allen Best

18

and reduce the number of dry holes.

These technologies, backed by powerful computers, converged with increased experience and the incentive of higher prices to create something of a perfect storm for exploration in about 2003, and today supplies are bountiful.

It’s been widely heralded as a game-changer.

Manufacturers are returning, enabled by cheap chemical feedstock provided as part of natural gas production. U.S. per-capita emissions of carbon dioxide have actually decreased in recent years as natural gas displaces coal for electrical production. Boosterish talk of national energy independence abounds. Some companies even want to export natural gas abroad.

In Colorado, lower natural gas prices have meant lower heating bills: Average household energy costs here are 23 percent less than the national average, according to the U.S. Energy Information Administration. The surging oil and gas sector also delivers paychecks for 30,000 people in the state and contributes handsomely to tax coffers. Colorado’s severance tax in 2012 yielded $163 million, half of which was distributed directly to local governments. A portion is also allocated to state water programs and loan funds via the Colorado Water Conservation Board. During the 2012 fiscal year, the Colorado Foundation for Water Education received 40 percent of its revenue indirectly from state severance taxes.

For billionaire energy entrepreneur T. Boone Pickens, all this is good. “I want to get rid of ethanol. I want to get rid of OPEC. I want to get natural gas in transportation,” he said in August 2013 at the American Renewable Energy Days conference in Aspen. “I don’t think I am talking to a group of people who are all that keen on drilling anything,” he added, but warned: “You’re going to have to deal with natural gas for 100 years. It’s going to be around that long.

We have a lot of natural gas in this country.”

That, in the view of skeptics, is exactly the point. It’s an issue of scale—and costs. What do we really know about the impacts to water? That’s not to mention the round-the-clock clanging, incessant lights, rumbling trucks and pungent odors associated with oil and gas development, all of this sometimes literally in suburban backyards, in fields next to schools, and in pastures where cattle graze. If Colorado is to be such a major source for oil and gas, shouldn’t we get it right—and now, not later?

Trési Houpt was elected as a commissioner in Garfield County in 2002 as drilling rigs sprouted conspicuously in the Piceance Basin. The basin arcs broadly from Carbondale through the Colorado River towns of Silt, Rifle and Battlement Mesa and toward one of Colorado’s oldest oil towns, Rangely. She says drilling companies weren’t communicating well with landowners then. That has improved. So have regulations intended to protect the environment and public health. But more, in her view, needs to be done.

“It could have happened to anybody,” she says of a spill of chemicals including the carcinogen benzene, a component of crude oil, found this year along Parachute Creek, a tributary to the Colorado River. “I think the contamination of Parachute Creek is just one more example of why we need to be extremely thoughtful about how we develop near waterways and whether we actually should.”

Colorado Foundation for Water Education

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Todd Patrick

Local Vs. State Authority

Trési Houpt, former Garfield County commissioner

Houpt, who also served on the Colorado Oil and Gas Conservation Commission from 2007 to 2011, is among many Coloradans who believe the implications of the oil and gas technology revolution have not been fully vetted. “Why not progress thoughtfully as we utilize this resource and, at the same time, work on the technologies that potentially could make it safer to drill in more populated or sensitive areas across the country?” she asks.

That is essentially the point Longmont is making, now followed by other cities along the Front Range, where citizen-based initiatives are seeking to put moratoriums on the use of hydraulic fracturing—and by extension, drilling altogether—within municipalities.

“Stop the fracking,” shouted one protester in May 2013 as Patty Limerick, noted historian at the University of Colorado Boulder, attempted to interview Gov. Hickenlooper at a forum in Boulder. Working to keep the session productive for the other 450 people in attendance, Limerick ordered her out of the room, and soon another heckler was similarly dispatched. But such extremes only frame the edges of what has become a difficult conversation.

The Rise of Natural Gas Drilling is hardly new in Colorado. In 1862, Colorado had a commercial oil well, thought to be second in the nation, near Florence, a few miles from Cañon City. Oil seeps led to development of a field north of Boulder in 1901, followed in 1920 by other fields near Fort Collins and Rangely. After World War II, the latter became one of the nation’s preeminent fields.

This post-war boom led to the creation of the Colorado Oil and Gas Conservation Commission (COGCC) in 1951. The agency initially set out to create order in the oil fields, to govern spacing in order to create more efficient extraction.

The original mission of “preventing waste of the state’s oil and gas natural resources” has since expanded, most significantly in recent years, to include broader environmental protections,

yourwatercolorado.org

Annual Colorado Oil Production

Tightening State Regulations

60 50 40 30 20 10 0

1952 1954 1956 1958 1960 1962 1964 1966 1968 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012

Millions of Barrels

70

1800 1600 1400 1200 1000 800 600 400 200 0

Northern San Juan Basin

Piceance Basin

Wattenberg

Statewide

Annual Colorado Gas Production

1952 1954 1956 1958 1960 1962 1964 1966 1968 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012

Billions of Cubic Feet

Rangely

Rangely

Northern San Juan Basin

Piceance Basin

Wattenberg

Statewide

Matthew Staver

These top-producing areas account for the majority of state production. Oil and gas obtained elsewhere nudge state totals up only slightly. Source: Colorado Oil and Gas Conservation Commission

Matt Lepore, Colorado Oil and Gas Conservation Commission director

the mission statement amended to: “fostering the responsible development of Colorado’s oil and gas natural resources.” Asked about the COGCC’s role in promoting development today, the agency’s director Matt Lepore replied: “We are not a cheerleader for the industry. We are not a marketing arm. We do not set quotas for them.” Rather, the agency oversees well permitting, investigates complaints, collects oil and gas production and water quality data, and enforces federal and state regulations.

As for natural gas, it was a nuisance at first, produced in the pursuit of oil and flared, to avoid explosion, until pipelines and other infrastructure were installed after World War II. It is often found with coal deposits, and hence the development, still continuing today, in the Raton Basin near Trinidad and the San Juan Basin around Ignacio, both in Colorado’s southern tier.

Since the late 1990s, the Piceance Basin has become a major natural gas-producing area. Pastoral and once-remote settings quickly became a patchwork of industrial zones. From the air, the well pads look like giant subdivisions of cul-de-sacs.

In recent years, industry attention has shifted to the Denver-Julesberg (DJ) Basin. Within that basin lies the highly productive Wattenberg Field, a lump of oil- and gas-bearing sands, shales and silts covering 2,500 square miles between Denver’s outskirts and Wyoming, Longmont and Keenesburg. The seminal or “discovery” well, Grenemeyer #1, located three miles northwest of Brighton, was started on March 6, 1970, and still produces today. Now, the Wattenberg has 22,000 active wells amid fields of wheat, alfalfa and other crops—and increasingly, suburban housing and exurban horse pastures. Their collective production is phenomenal: 120,000 barrels of oil per day during February 2013, or about three-quarters of Colorado oil production. Plus, there was more than 850 million cubic feet of gas per day, roughly enough to supply the gas used to heat eight million homes.

Amassing the Wattenberg, Piceance and all other fields, oil production in Colorado hit 49 million barrels in 2012, still short of the record of 58.5 million set in 1957 but with growth trends in recent years as steep as the face of Longs Peak.

Continued on page 22 Headwaters | Fall 2013

To keep up with technological advances and address concerns about impacts, the Colorado General Assembly in 2007 directed steppedup regulation of oil and gas development. Over the protests of drilling companies, the first major series of regulatory reforms by the Colorado Oil and Gas Conservation Commission (COGCC) came in 2008. The regulations addressed siting, construction and operation of storage tanks, and also required all open pits used for storing waste fluids be lined to certain specifications, among other things. Standards continue to be tightened. For example, Gov. John Hickenlooper in 2013 signed legislation requiring spills of more than one 42-gallon barrel, a smaller volume than previously required, be reported to state regulators within 24 hours.

Are additional measures needed to guard against contamination of water sources?

Opinions vary. New 2013 state provisions raise the minimum distances that wells must be sited from houses and other occupied structures. Previous setback distances of 350 feet for high-density areas and 150 feet elsewhere have been bumped to a uniform 500 feet statewide, and 1,000 feet for high-occupancy buildings such as schools and hospitals. The new rules also mandate less risky procedures for sites within 1,000 feet of occupied structures, such as closed-loop systems that recirculate fracturing fluids in order to avoid the need for pits to store waste fluids.

State regulators says the most significant rules concerning water quality protection pertain to the installation of the steel casing and cement lining used to isolate the well bore as it pierces geologic layers where potable groundwater is found. Such isolation is required for all oil and gas operations, including fracking.

The COGCC also instituted new baseline water quality monitoring requirements in May 2013.

Sean Lieske, environmental permitting manager for Aurora Water, explains that concerns for municipal water providers extend beyond the process of drilling and hydraulic fracturing below ground to potential surface impacts from spills during both production and transportation. Drilling has recently been initiated within Aurora’s borders. And the Bureau of Land Management, which controls land containing 13 percent of the state’s oil and gas wells, has also offered mineral leases for parcels in the area of Spinney Mountain Reservoir, the city’s impoundment in South Park for municipal water. “While there is an existing regulatory framework in place, we would like greater certainty to assure that our water resources are adequately protected,” says Lieske. –Allen Best Anadarko Petroleum and others have announced billions of dollars in investment in the Wattenberg. Anadarko estimates that the field contains 1 to 1.5 billion barrels of oil equivalent. By comparison, the United States consumed 6.87 billion barrels in 2011, according to the U.S. Energy Information Administration.

19

How Hydraulic Fracturing Works 1

HORIZONTAL DRILLING

2

Horizontal drilling takes a vertical well bore and extends it to the side, in order to gain access to unconventional oil and gas deposits. Multiple horizontal wells can be drilled from one location, reducing surface impacts while maximizing output.

New Colorado regulations require baseline testing and monitoring of up to four water wells within a half-mile radius of an oil and gas well.

Derrick

CASING

Storage for waste fluids

Since 2008 all waste storage pits are required to be lined, and some must be fenced or covered to protect wildlife and migratory birds.

HYDRAULIC FRACTURING

Fracturing begins with millions of gallons of water plus proppant and chemicals pumped into the well at high pressure to fracture the formation.

Storage tanks Freshwater

Proppant

It can take up to 1,000 tanker trucks to transport enough water for fracking a well.

9.6 in.

Cemented to the surface Conductor casing

Wellhead

Chemicals

Cement

Surface casing

UP TO 10,000 FEET DEEP

IMPE RVIOUS ROCK

To reach the average well depth in the Wattenburg Field, 7,900 feet, would require more than 11 of Denver's Wells Fargo buildings be buried end-to-end.

Faulty casing around bore

A QU IFE R

A QUIFER

BORE

WHATâ&#x20AC;&#x2122;S IN FRACTURING FLUID?

Must extend at least 50 feet below potable groundwater and be tested for integrity before drilling continues.

80.5% Water 19% Proppant

CASING CROSS-SECTION Intermediate casing

Sand and/or man-made ceramics that lodge in the fractures, holding them open

0.5% Chemicals

Production casing Surrounded by cement the length of the well.

4.5 in.

KICKOFF POINT â&#x20AC;&#x201D; WHERE DRILL BORE STARTS TURNING

Minimize friction, increase viscosity, and inhibit bacterial growth. Some are benign, others toxic.

Colorado's 2012 chemical disclosure rule requires operators to report chemicals used as a percentage of total fracturing fluid via fracfocus.org.

WELL HEEL SHALE FORM ATI ON

SHALE FORM ATION

UP TO TWO MILES IN LENGTH 20

Colorado Foundation for Water Education

llustration by Charles Chamberlin

OIL AND GAS RECOVERY

Once used fracturing fluid, called flowback water, is pumped to the surface, oil or gas begins to flow to the wellhead. If infrastructure for capturing gas in pipelines is non-existent, the initial output of gas is flared or vented. The flowback water is stored and transported for disposal or reuse.

Air quality potentially affected by gas leaks Flare vent

Waste fluids, stored in a pit or portable tank, are collected and hauled to a treatment plant for recycling or injected into a disposal well.

Seepage from poorly constructed waste fluid storage

CAUSES FOR CONCERN STATE REGULATIONS (Under Colorado Oil and Gas Conservation Commission) Disposal well

Gas/oil tanks

Leaks from storage tanks and pipelines Gas/oil piped to market

Gas/Oil piped to storage

STEPS IN MULTI-STAGE HYDRAULIC FRACTURING 1 Perforation gun is inserted

into production casing to the well toe and fired, creating holes in the casing and surrounding cement.

2 Isolation plug is inserted in the

casing and the perforation gun is reinserted and fired. This step is repeated along the length of the horizontal bore.

Cement

Perforation gun

Production casing

Under the U.S. Environmental Protection Agency's Underground Injection Control program, Colorado regulates the location and vertical depth of disposal wells, as well as the volume of fluid that can be injected.

Isolation plug

Production casing

3 Isolation plugs are drilled

out, and pumps inject fracturing fluid into the well at approximately 1,500 pounds per square inch of pressure, fracturing the shale.

4 Water is pumped out, leaving proppant lodged in the fractures and allowing gas and oil to flow to the wellhead.

Some chemical agents remain in ground and are not biodegradable

Frack fluid

Gas

Watch an animated depiction of hydraulic fraturing at: www.youtube.com/watch?v=VY34PQUiwOQ

WELL TOE

AL LEAST 2,500 FEET BENEATH DEEPEST POTABLE WATER SOURCE

3

Seepage from disposal wells

Diagram not to scale

Sources: Colorado Oil and Gas Conservation Commission, Colorado Oil and Gas Association, Exxon Mobil, New York Times

Headwaters | Fall 2013

21

Continued from page 19

Colorado Leads in Baseline Testing In May 2013, Colorado set a national precedent: New regulations require monitoring of up to four water wells within a half-mile of proposed oil and gas well pads. Oil and gas companies must pay for sampling and analysis before drilling begins and then twice more—at approximately one and five years after drilling.

Colorado was the third state in the nation to require groundwater sampling before drilling.

Now it is the first and, at this point, only state to require sampling again after drilling.

State regulators believe this level of baseline monitoring will improve early detection of any hydrocarbon or hydraulic fracturing fluid migration to potable groundwater and aid understanding of whether there are adverse long-term impacts associated with drilling.

Some baseline data was recorded previously under rules requiring similar testing specifically on coalbed methane wells and wells in the northern Front Range’s Wattenberg Field, as well as a voluntary groundwater monitoring program run by the Colorado Oil and Gas Association. The industry trade group, which represents approximately 85 percent of operators in the state, reported a 90 percent participation rate in its program by members.

Bruce Baizel, the Durango-based energy program director for Earthworks’ Oil and Gas Accountability Project, credits Colorado with taking significant steps—but wants more: To avoid a Russian Roulette arrangement, all water wells within a half-mile of the proposed drilling should be sampled before and after, as opposed to just a few, he says.

However, with testing costs ranging from $2,000 to $4,000 per well, and some drilling sites containing 10 to 20 or more water wells within a half-mile radius, the Colorado Oil and Gas Conservation Commission concluded during its rule-making in early 2013 that four wells struck a balance between accurate documentation and monitoring and the financial costs of sampling. –Allen Best

Locate wells drilled or permitted in your area, search a database on reported spills, and get updates on hot topics at the Colorado Oil and Gas Conservation Commission’s website: cogcc.state.co.us.

Find out what chemicals are being used on a well-by-well basis via the FracFocus database: fracfocus.org.

22

Production of natural gas as represented on bar charts for decades looked like a profile of the Great Plains, almost imperceptibly sloping upward. Now, the industry is in more rugged territory, the annual growth heady stuff.

Water Quality at Risk?

Over the years, concerns have grown that drilling could contaminate local water supplies. The proximity of the Wattenberg Field to residential areas has served to amplify citizen outcry. Many allege that Colorado laws governing drilling are too lax, that the protection of vital water supplies is disregarded in the frenzy to tap the resource.

The focus of the attention has been on fracking.

It’s true there have been spills and other evidence of mistakes, all of them cause for concern. But with 51,000 active wells in Colorado, most of them fracked, the chemicals used in the process have never been shown to migrate underground to drinking water supplies as many have feared. That’s not to say it couldn’t happen. It’s just unlikely.

Aquifers tapped for drinking water are typically found within 1,000 feet of the surface.

Oil and gas drillers plunge concentric circles of steel pipe through these shallower layers of rock containing potable water, encase the pipes in layers of concrete, then drill much, much deeper through impermeable layers of what are called cap rocks. These impermeable layers are what have kept the oil and gas underground over eons. In the layers 3,000 to 10,000 feet below ground are the hydrocarbons—and also more water. This deeper water is usually salty, leftover from ancient oceans and seas, and high in dissolved minerals, making it unfit for human consumption.

Limiting the discussion to what is happening underground, potable groundwater supplies can theoretically be harmed by drilling and hydraulically fracturing a well in just two ways: 1) if the steel casing or concrete lining the well bore fails, or 2) if the fractures themselves create pathways extending thousands of feet upward. As regards the latter possibility, energy companies have a vested economic interest in measuring and controlling the length of fractures, in order to reduce the quantity of frack fluids required and protect their ability to drill additional, nearby wells without risking uncontrolled interactions. Microseismic technology enables them to “read” the measurements underground, and the COGCC reports fractures remaining in the “formation of interest” and rarely extending beyond several hundred feet. Even those fractures that reach 1,500 feet typically extend more horizontally than vertically, and remain thousands of feet below groundwater sources.

Although standards are in place to monitor the integrity of well casings, which must extend below potable groundwater supplies, the technique isn’t perfect. Of the 38,000 wells drilled in Colorado since 1990, there have been 15 cases—and possibly a 16th yetunresolved case—where well-bore failures led to groundwater contamination by methane, the primary component in natural gas. Most of these failures occurred prior to 2008, when state rules were changed to require steel casing and concrete extend 50 feet below the

Colorado Foundation for Water Education

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deepest aquifer being used for drinking water.

In 2004, for example, a well-bore failure occurred near Silt, west of Glenwood Springs, resulting in methane bubbling from West Divide Creek. The operator, Encana, was fined $371,000. That same investigation in 2004, however, cleared oil and gas activities in the case of methane detected in a private water well along West Divide Creek. The methane there, said state inspectors, came from naturally occurring, near-surface, “biogenic” sources—as opposed to the deep “thermogenic” methane targeted by energy companies. Isotopic testing allows chemists to make the distinction. Although considered harmless if swallowed in water, methane quickly outgases, releasing into the air where it can become explosive.

While methane contamination has occurred, no evidence exists to show fracking chemicals migrating to reach groundwater used for drinking. Not just in Colorado, but nationwide, in fact, there has yet to be any conclusive proof of such contamination occurring. In 2011, the U.S. Environmental Protection Agency released a draft report saying groundwater at Pavillion, Wyoming, was fouled by 13 different chemicals used in fracking fluids, chemicals the agency concluded were introduced during the injection stage of hydraulic fracturing. The agency’s conclusions about how the chemicals came to be in the water samples taken, however, are hotly disputed. The EPA has since stepped aside to let Wyoming state officials further investigate.

Some see the move as a sign the EPA recognizes its science was critically flawed, though the EPA continues to stand by its data. The stateled study will be funded, in part, by a $1.5 million grant from the oil field’s operator, Encana.

Chemical Disclosure What worries some is not what we know. Rather, it’s what we don’t know. A major sticking point has been the lack of transparency about content and quantities of fracturing fluids. How can regulatory agencies monitor for chemical compounds they don’t know to be looking for?

The Energy Policy Act passed by Congress in 2005 excluded fracking from disclosures required by the Safe Drinking Water Act—under which the EPA regulates the injection of fluids underground. In halting steps, states have instituted their own requirements. The nonprofit Groundwater Protection Council in 2011 set up a national Web-based system for voluntary disclosure called FracFocus.

In Colorado, the public disclosure of ingredients used in fracturing fluid was first required upon demand of public officials and healthcare providers. In 2012, Colorado made disclosure via FracFocus a mandatory requirement. All chemicals used since then must be disclosed as a percentage of the total mass of the fluid, but companies remain exempt from reporting their proprietary “recipes.” At the time it passed, Colorado’s disclosure rule was the strictest in the nation, says Lepore. “The Environmental Defense Fund and industry came together and supported the rule. It was a big moment, a rare moment,” he says. Since then, Pennsylvania, Ohio and Tennessee have mod-

yourwatercolorado.org

eled their disclosure rules after those here.

Mark Williams, of the University of Colorado, believes the industry hurt its own cause by being secretive, which allowed worst-case fears to flourish. He sees little risk from fracking, but says the public worries are easily understood. “The potential of contamination by fracking fluids is really, really low—but not zero,” says Williams, a hydrologist who is co-leading a $12 million program funded by the National Science Foundation to explore fracking and other issues involving oil and gas extraction.

But how do we know the risk is low? Some argue that we don’t—unless we have baseline data that records water quality before drilling occurs and then again afterward. Although such data exists for certain regions—in the San Juan Basin, for example, the Colorado Oil and Gas Association reports more than 2,000 samples have been recorded since 2000 with no evidence of impacts to groundwater wells adjacent to drilling activities—it isn’t a complete picture. Colorado began requiring monitoring statewide in May 2013.

“It’s absolutely essential. We need to know what the conditions are in terms of water quality, before oil and gas is extracted, to know if there is a perturbation, or a problem, of contamination,” says Williams. What must be understood, he adds, is that the potential for contamination varies widely as a function of the hydrogeology.

“Just because there has been some contamination of a rock formation elsewhere in the United States doesn't mean that you have an increased likelihood of contamination where you are. It depends upon the hydrogeology of your area.”

To help resolve the uncertainties, Congress in 2010 ordered the Environmental Protection Agency to undertake a major transparent, peer-reviewed study of the potential impacts of hydraulic fracturing on drinking water resources. The draft study is scheduled for public review in 2014.

What Goes Down Must Come Up Of greater concern than fracking to Williams are the above-ground handling of fluids and the deepwell injection of waste. Millions of gallons of water are forced down wells in fracking operations, and much of that water—along with frack chemicals— returns to the surface. Called flowback water, it must be collected, transported and disposed of.

So must produced, or formation water, which is water pre-existing in the hydrocarbon-containing formations that must be removed to bring up the oil and gas. In the case of coalbed methane wells, which are shallower than other oil and gas wells, the quality of the water is typically high and, in some cases, can be released into streams with little or no cleanup, subject to state water quality standards. Produced water from deeper sandstone formations is more challenging because it is commonly, to use a non-scientific term, nasty— full of salt and dissolved solids. But sometimes it can be of reasonably high quality and could even be a resource for the future.

Spills and leaks of hydrocarbons and waste fluids, both from storage pits and tanks as well as pipelines and trucks during transport, pose a far greater concern than the actual fracturing process itself, say regulators. About 500 spills occur per year on average in Colorado, according to the

COGCC. One such accident occurred in February 2013 when a mechanical failure resulted in 80,000 gallons of frack fluid gushing from a well north of Windsor. In a negotiated settlement with COGCC, the operator agreed to pay $35,000, which was seen by some as a mere hand slap but was four times the maximum fine currently allowed by law.

A more extensive fine could have been levied had “extensive environmental damage” been proven, but Lepore said no impacts occurred off the well pad or to groundwater. Soils on the well pad were quickly scraped and disposed of. The relative containment of the spill made a difference in the concern, the response and the potential penalties, says Lepore.

Gaining more attention was a leak discovered along a pipeline in Garfield County, which has led to benzene contamination in Parachute Creek.

The company responsible for the pipeline made the discovery and notified state regulators, but not before more than 10,000 gallons of hydrocarbons had escaped. Some saw this as a wake-up call that buried pipelines across the state, subject to corrosion, pose a looming hazard for environmental integrity. Others saw it as evidence the state is too thinly staffed.

Colorado currently has 19 inspectors charged with monitoring initial drilling and ongoing operation of the state’s 51,000 operating wells. Last winter, the Colorado General Assembly authorized hiring additional inspectors, to a total of 27, which could help the COGCC better enforce its safety regulations. “The regulations are actually quite good,” says Williams, “but regulation is not compliance.”

In September 2013, risks to water quality were again highlighted when flooding waters in the South Platte River Basin toppled tanks and in other ways resulted in what state officials reported were 12 notable releases of oil. Although 1,300 wells were shut down, the releases are expected to cause state officials to review regulations for drilling in floodplains.

Improving Safety Measures One strategy to reduce spills and improve safety measures is to instill a culture of best practices.

The Colorado Oil and Gas Association (COGA), an industry trade group, has arranged speakers at its annual conventions to make the case for stepped-up acceptance of environmental quality as a cost of doing business. And Mike King, director of the state’s Department of Natural Resources, this year advised companies to go above and beyond state requirements and reach out to communities. Such efforts won’t always be well-received, but they are essential to building community confidence.

Economics have also improved some practices. While newer state regulations require that companies pay to install more rigorous linings for waste-holding pits, some operators have gone another route, investing in pipelines to consolidate water-handling operations from several well pads at one facility. Encana estimates it has eliminated 120,000 truck trips per year in its Piceance Basin operations by collecting flowback fluids into pipelines that feed the company’s four water treatment plants— and then transport that water to be reused at Headwaters | Fall 2013

new drilling sites. Fewer truck trips mean less potential for spills, as well as reduced emissions and dust from truck traffic.

Reusing water—and also reducing the amount needed—also means operators don’t need to purchase as much high-quality water from municipalities or other providers. Noble Energy, with a goal of reducing water needs to near-zero, has dedicated what are described as “significant resources” to figuring out how to achieve that goal.

“It’s a good thing to do, but it’s also a prudent business practice,” says Ken Knox, senior advisor and water engineer for Noble. The greatest challenge, he says, is that water quality differs based on the geologic formation, “so we have to adapt to site-specific conditions.” What works in the Piceance Basin, for example, where the quality of produced water tends to be higher, doesn't work in the Denver-Julesberg.

In Colorado, 51 percent of produced water and flowback is not recycled or treated and released, but injected into deep wells, some specifically designed for that purpose. Colorado has 325 such wells, but fluids are also injected into 575 non-producing oil wells in order to force lingering hydrocarbons through the formation and increase productivity in nearby wells.

Neshama Abraham, a steering committee member of Frack Free Colorado, points to many concerns about current disposal methods, as well as the plugging and abandonment of nonproducing wells. One of them involves the durability of concrete liners. “Who is available to see if there are cracks in that 50-year-old cement thousands of feet under the ground?” she asks.

Like oil and gas wells, disposal wells must be lined and cemented beneath the deepest potable aquifer, and the COGCC requires companies take steps to ensure the integrity of well casings. Cement bond logs, for example, are a required test to confirm the cement sealed properly. Pressure tests are used to monitor for potential breaches, and mechanical integrity tests are conducted every five years to look for holes in the casing of disposal wells. But Lepore concedes that the 40,000 plugged and abandoned wells in Colorado are problematic, in that procedures for plugging wells have changed over time. And only sketchy records of wells drilled prior to 1951 exist.

Still, drawing from her experience moderating the Center of the American West’s FrackingSENSE series in early 2013, Limerick believes that air quality, especially because of the greenhouse potency of methane, may be a more deserving target for public anxieties regarding natural gas drilling than water contamination by hydraulic fracturing. But she does acknowledge risk. “Risk will never be entirely eliminated from the world of natural gas production…nor from the world of highway travel, cardiac surgery, food safety, recreational skiing, etc.,” she says.

She also cautions that the way scientists calculate probabilities of risk is very different from how “civilians” perceive them. The scientist has a non-personal assessment. The public views risks in an entirely personal way.

“The scientists are trying to speak in statistical terms about broad populations; the public is asking, ‘Am I in danger?’” q 23

Matthew Staver

A tanker-truck driver fills up at a water hydrant in Greeley prior to heading out into the oil fields, where the water will be used for drilling or hydraulic fracturing.

Colorado is expected to need an additional 41,500 to 78,500 acre feet of water for power production and 1,000 to 50,000 acre feet for energy development by 2050. Source: Statewide Water Supply Initiative 2010 24

Colorado Foundation for Water Education

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yourwatercolorado.org

Power in the Marketplace How Companies are Pursuing and Acquiring Water to Power Colorado

By Caitlin Coleman In July 2012, the city of Aurora stopped negotiating. They had exchanged their last term sheet, and the city council voted eight to three in favor of striking a deal—the Anadarko Petroleum Corporation could lease water from Aurora for five years, with an option to extend for another five.

Suddenly the Front Range was buzzing with news of the lease. Some papers ran just the facts: Anadarko would pay the city a healthy $9.5 million total, or $1,200 per acre foot of water, receiving 1,500 acre feet each year. Other stories featured the emotional side—the worries and upset of citizens.

“We were surprised at the response, because, when you stripped off the uses of water, it seemed like a normal deal with many of the same elements as before,” says Lisa Darling, Aurora Water’s program manager for the South Platte River Basin, who negotiated the deal.

Headwaters | Fall 2013

25

Water for Energy Just like any other water user looking to access the resource, energy companies have options.

Although new energy developers likely don’t own the most senior water rights, they can apply for new junior rights, or can acquire and change a senior right, legally altering its use.

The Colorado Division of Water Resources is 26

Kevin Moloney (3)

It was normal, in that Aurora leased some of its excess water supply—a customary practice for the city. But the end-user here, Anadarko, will employ the water in oil and gas development, using it for drilling and hydraulic fracturing in Weld County. This was new for Aurora.

Recent years have heralded other negotiations that link water rights holders to energy or power companies, with varying outcomes. Both energy companies, which extract natural gas, oil, coal, uranium or other energy-producing minerals, and power companies, which use those fuels or renewable sources to generate electricity, require water for their operations, which in Colorado means access, in some form or another, to a water right.

Water rights for energy are nothing new. In fact, Colorado’s prior appropriation system, commonly summed up as “first in time, first in right,” is rooted in early hardrock mining, where it was first applied. This system, now administered across all “beneficial uses” of water in the state, allows for those with older, senior rights to use water before those who hold newer, more junior rights in times of shortage. Although power plants have been around for decades with water rights of their own, their water supply portfolios are changing, while oil, natural gas and coalbed methane production has been growing in a fast, new fashion. All require water.

Still, the numbers seem small. As of 2011, according to the Colorado Water Conservation Board and Division of Water Resources, an estimated 0.47 percent of the state’s current water withdrawals went to thermoelectric power generation; 0.03 percent to coal, natural gas, uranium and solar development; and 0.04 percent to hydraulic fracturing. Compare that to the 86 percent that goes toward agriculture and 8 percent to municipal and industrial uses, and energy’s share looks insignificant.

But in a water-short state, where most supplies are already allocated, many players are competing for the same water, and new uses are being closely scrutinized. Fierce competition can also drive up costs, excluding some from the marketplace. And while water needs for power remain fairly consistent, some say there isn’t enough data to truly account for the energy industry’s water demands as comprehensive statewide water resource planning unfolds.

“It’s sort of a moving target at this point because things are changing so fast,” says Laura Belanger, a water resources engineer with Western Resource Advocates. Belanger’s group estimates that if oil and gas development continues at a rate similar to the present, water needs for Colorado’s new oil and gas wells alone will range from 22,100 to 39,500 acre feet annually by 2015. That equals the water needs of up to 79,000 Colorado households for a year, but results in the production of all the natural gas used in the state—and then some.

Lisa Darling

“When we first began negotiating, we were surprised to find that the [oil and gas] parties were willing to talk about rates that were typically three or four times more than where the market had been previously.” —Lisa Darling, Aurora Water involved in such change cases, like any other, to make sure the final outcome doesn’t affect other senior water users’ ability to obtain their allotted water.

Leases such as the Anadarko-Aurora deal are a better short-term option and require less legal oversight than purchasing, changing and owning a water right. “Municipalities have a lot of freedom to lease water to oil and gas or other kinds of users,” says Tracy Kosloff, water resources engineer with the Division of Water Resources. Kosloff works on well permits as well as temporary and permanent changes of water rights from their original use to new uses. In the case of a lease, the municipality or other leaser, such as an agricultural user, owns the water right and has to divert, obtain and account for the water in accordance with their legal decree.

The contract is between the water rights holder and the lessee. “Basically [the municipality is] providing water to a customer within their service area,” says Kosloff.

Aurora, for instance, plans its water supply to ensure there is enough during drought and for projected growth. The city secures water when it’s available and leases the excess until it’s needed years down the road. The water Anadarko leased is a small portion of the city’s excess—in this case, treated wastewater the city would otherwise be entitled to reuse if the infrastructure were in place to do so.

Drilling a well to pump groundwater or entering an agreement with a well owner is also possible, though the majority of wells withdraw tributary groundwater, which is water connected underground to surface streams. To protect senior water users in the system, these wells require an augmentation plan for replacing depletions that would have otherwise reached the river. Well users must somehow acquire or purchase that replacement water from another source.

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Tracy Kosloff

“Municipalities have a lot of freedom to lease water to oil and gas or other kinds of users.” —Tracy Kosloff, Colorado Division of Water Resources

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Suzanne Jones

“We would rather use this valued and limited resource, [water], to support our people in growing food and maintaining healthy rivers and landscapes.”

—Suzanne Jones, Boulder City Council Nontributary groundwater, however, is not connected to a stream system and can be used without augmentation—a preferable arrangement for an energy company. Permitting for nontributary wells is based on the estimated amount of water contained beneath that land’s surface area—and limited to a withdrawal rate of 1 percent per year assuming a 100-year life of the aquifer. The Division of Water Resources has seen a recent increase in nontributary determination applications: There were two filed in 2010 and zero in 2011. That jumped to five filed in 2012 and six that reached Kosloff’s office in the first eight months of 2013.

This nontributary water is often so far beneath the surface that it’s not cost-effective for other, nonenergy users to access, says Kosloff.

Local Leasing Decisions Leasing water rights is an attractive option for energy companies, who typically have shorter-term demands for water compared to power companies. Water is used to drill and possibly hydraulically fracture a well, but isn’t necessarily required for ongoing production, although sometimes wells are fracked multiple times over their productive life.

For municipalities, the attraction of leasing arrangements is usually financial—oil and gas companies have money and are willing to pay. Aurora charged Anadarko four times their usual excess water lease rate of $300 per acre foot. Now the rate has risen even higher. “When we first began negotiating, we were surprised to find that the [oil and gas] parties were willing to talk about rates that were typically three or four times more than where the market had been previously,” Darling says. “Now we hear the price has escalated even further. Obviously, the water lease market is in a state of great flux.”

Other towns are also leasing excess water supplies, particularly those closest to Weld County, where the majority of the state’s current drilling

activity is centered. And many towns that receive Colorado-Big Thompson Project water from the Northern Colorado Water Conservancy District are leasing excess water when it’s available as well. Erie, Fort Lupton, Greeley and Longmont have reaped big benefits and, in some cases, are paying down debt with the leasing revenues.

Residents see the benefit coming back to them through lower water rates. Aurora, for example, completed its $680 million bond-financed Prairie Waters Project in 2010, but residents have seen no increase in rates over the past few years, in part due to the Anadarko lease.

Still, other municipalities are closely guarding their water. In June 2012, the town of Windsor decided to take a step back from leasing large quantities of water to oil and gas development.

The town had just begun leasing water in November 2011, but the rush of demand was higher than expected and more than local leaders were comfortable supplying. Windsor sold 8.4 million gallons—nearly 26 acre feet—of water to six oil and gas well servicing companies between November 1, 2011, and March 1, 2012, bringing in more than $16,800. But by June, the city council had approved an ordinance to restrict the volume of water used at hydrants—where trucks bound for drilling sites were filling up—and to raise the rate for large users.

Doug Flanders, director of policy and external affairs for the Colorado Oil and Gas Association, doesn’t mind a city’s decision to limit sales—he sees that as no different from a watering restriction—but he worries about completely prohibiting water sales for hydraulic fracturing. “When you prohibit something, is that a discriminatory business practice?” he asks. “We will sell you this, but not this; they can buy it, but not you; they can drive my road, but you can’t. Can they do that? I don’t know.”

Boulder is currently testing those limits. In Headwaters | Fall 2013

June 2013, the Boulder City Council unanimously passed an ordinance prohibiting the use or sale of Boulder’s water supply for hydraulic fracturing. “We would rather use this valued and limited resource, [water], to support our people in growing food and maintaining healthy rivers and landscapes…We don’t want to be selling our water to support something that we’re not sure should be happening,” says City Councilwoman Suzanne Jones.

Although other municipalities have recently made similar decisions to restrict hydraulic fracturing within their borders, Boulder is Colorado’s only city so far to specifically prohibit water use for the practice. In fact, Boulder isn't sure that nonrenewable energy development should be happening in any form. The city has decided not to renew its contract with Xcel, in part due to failed negotiations over adding more renewables to its energy portfolio, and is now in the process of forming its own municipal utility. “We think it’s really important to try to decarbonize our supply in the face of climate change,” Jones says. “We are very interested in getting off fossil fuels as quickly as possible while maintaining our robust economy and fuel prices.”

Some leaders in Boulder are also concerned about the availability of water rights for farmers, worrying that farmers are being outbid, Jones says. During periods of drought, this is more of a concern because of heightened competition.

Although farmers who hold senior irrigation water rights aren’t typically bidding against the energy industry, others rely partially or completely on purchasing excess supplies.

Nick Colglazier of the Colorado Farm Bureau says his organization supports Colorado’s market-based system, where water rights are treated as property rights that can be bought, sold, leased and transferred between any willing buyer and seller. “This [bidding up of prices] does ruffle some feathers in the ag community since water is a scarce resource,” he acknowledges. “Some farmers do depend on leasing water from cities and this competition makes it harder and more expensive to acquire.” But, he adds, while the bidding power inequity between players in the marketplace is likely to be an ongoing conversation, “Most of the voices you hear complaining about oil and gas taking ag water are those outright opposed to the process of hydraulic fracturing.”

Water for Power Electrical companies and power generators haven’t been paying quite the same premium for their water. Rather, they pay a middle-tier rate for their leases and purchases based on the term of the lease (usually long), the volume of water taken (typically large), and likely because most of their leases were contracted before there was competition with the energy industry.

In the case of thermoelectric generation, where the majority of Colorado power comes from, water is critical for cooling and condensing steam in generating stations. Large quantities of water are required—and an average of 90 percent of water sourced statewide for thermoelectric power production is completely used up in the process. Still, the share of water going to meet the daily electricity needs of the typical Colorado residence roughly equates to taking a three-minute shower, says Rich Belt, water resources analyst with Xcel Energy.

Power generation is a more visible and con27

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Matthew Staver

stant use of water than energy extraction. A company simply can’t let the power go out because of a drought or other interference, and so Xcel Energy and others have worked to diversify their water portfolios.

“It’s kind of like the advice you might get from a money manager if you buy a mutual fund: You’re diversifying your risk if you don’t have all your eggs in one basket,” Belt explains. Xcel has what Belt refers to as a “bundle of sticks” approach—different sources of water in each of Colorado’s seven water divisions statewide, including transferred rights, leases, junior rights, storage—plus the ability to legally move water up and down rivers, in effect tying together supplies for all of Xcel’s thermoelectric power plants within a river basin.

This dedication to resiliency has meant more cooperative projects among water users. In Sterling, Xcel entered an agreement with the Point of Rocks Water Company to hedge against an unforeseen or catastrophic event or drought. Now, if Xcel calls for water, Point of Rocks will deliver that water out of its reservoir, reducing the amount available to irrigators. This ensures Xcel has an adequate water supply to operate its nearby Pawnee Station, even in drought years, Belt says. In exchange, Xcel pays Point of Rocks an annual fee, and if it were to exercise the agreement, Xcel would pay per acre foot of water delivered. That extra money could, in turn, help Point of Rocks irrigators through dry times when crop yields suffer.

Another agreement is benefitting Tri-State Generation and Transmission Association—and the Yampa River. In 2012, the Colorado Water Trust began Colorado’s first temporary water leasing program to wet dry riverbeds during the summer’s drought. The Upper Yampa Water Conservancy District approached the nonprofit with 4,000 acre feet of water they were willing to sell to the program, but with the condition that the leased water be put back into another form of beneficial use.

Tri-State jumped on board to use the water for electrical generation downstream.

Throughout summer 2012, the leased water rushed out of Stagecoach Reservoir, providing a constant flow to boost the Yampa. From Stage-

As water resources analyst with Xcel Energy, Rich Belt manages planning, operations, legal and legislative tasks related to the company’s water needs.

coach to Lake Catamount, that water was protected by an instream flow water right, but the Colorado Water Trust wanted to move that water beyond the protected reach through the town of Steamboat where people enjoy tubing and fishing—unless flows are low, as they were early that summer. TriState’s participation in the agreement ensured the water would be shepherded through Steamboat all the way to Tri-State’s coal-fired power plant in Craig. The lease was repeated, but structured differently, during 2013’s summer months.

Water use for energy and power is only going to increase over coming decades, according to state and industry projections, but conservation and recycling lessen the demand. In Longmont and a few other locations, Xcel trades water, exchanging fresh mountain Colorado-Big Thompson Project units for an equal amount of wastewater effluent. “It keeps [Longmont’s] treatment cost down.

It’s obviously better water for their users and the wastewater effluent is fine for us,” Belt says. The future for Xcel looks like more natural gas plants and renewables such as wind and solar—which

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should translate to decreased water use.

For oil and gas, recycling and reuse of water are improving. On the Western Slope, Encana recycles more than 95 percent of water used for or produced during drilling—this waste water cycles through the company’s four water treatment plants and is piped through a 300-mile network of pipelines to reach wells where it’s reused for hydraulic fracturing. Each barrel of water is reused an average of 1.33 times before disposal, says Encana spokesman Doug Hock.

“Everybody talks about what can we [the oil and gas industry] do to save water, and we’re doing it,” says Flanders. “We’re becoming more efficient with our water, we’re recycling more water, we’re doing everything.”

Others say the industry could still do better, arguing that the state’s current deep well injection rate of 51 percent of contaminated drilling waste fluids removes a substantial amount of water entirely from the water cycle.

Belanger believes the energy industry is trying to recycle wherever possible. Still she calls

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Water Used For Daily Household Electricity Needs

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HOURS

9.7 Gallons of Water for Electricity Generation

To power the average Colorado home (711 kilowatt hours/month) requires approximately 9.7 gallons of water per day at Xcel facilities, based on the fleet’s system average water consumption rate (410 gallons/megawatt hour). Source: Xcel Energy

for more data on what demands for energy and power will look like in the future—and better incorporation of this information into water supply planning. She points to the 2010 Statewide Water Supply Initiative, which includes an oil and gas section but lists no energy demands for the South Platte Basin. “For some reason [oil and gas development] took off so fast, we just missed it in the last round of SWSI planning,” Belanger says.

“As we look forward and plan and figure out how to meet urban, agricultural and environmental

water needs, we need to make sure [water demands for energy] are considered.”

The Colorado and Yampa/White basin roundtables attempted to fill the data gap several years ago by commissioning an Energy Development Water Needs Assessment for northwestern Colorado. Of particular interest were the extensive potential needs associated with oil shale development, which seemed poised to take off. The study found that overall long-term energy-related water demands for the basins

Headwaters | Fall 2013

range from 5,705 acre feet to 151,730 acre feet per year—the range due to the uncertainty of oil shale, which alone could require up to 120,000 acre feet per year. With oil shale development currently stalled in the face of the natural gas boom, the energy demands in Colorado’s northwest corner are far more modest.

“It [energy’s water demand] is big, but it is not insurmountable,” says Dan Birch, deputy general manager with the Colorado River District and energy subcommittee co-chair for the two roundtables. “If energy development is going to occur, it’s going to occur and water is not going to be a limiting factor for it.” But, he adds, “We want to make sure those demands are folded into the planning process that’s underway right now so they’re not forgotten.”

In May, Gov. John Hickenlooper issued an executive order that the Colorado Water Conservation Board commence work on a state water plan, complete a draft by December 10, 2014, and finalize the plan by December 10, 2015. Among other things, the governor’s order asks that the plan emphasize projects that stress conservation, innovation and collaboration—a sound directive.

Fortunately, Colorado is already seeing some such projects. From plans that prepare regions to integrate oil and gas development with other water demands, agreements ensuring that each drop of water sees many uses, and win-win water exchanges, cooperation is a form of friendly etiquette—born of necessity. The sooner Colorado can manage water in ways that work for everyone, says Darling, the sooner we can become more successful as a state. q

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