Click here to read the update (Megan Holcomb & Tracy Kosloff):
Water Year 2020 has concluded as the 12th warmest water year on record in Colorado since 1895. The winter months presented near normal temperatures with warmer temperatures occurring throughout summer months. Water Year 2020 was the third driest water year on record, trailing only 2002 (driest) and 2018 (2nd driest). October temperatures were above normal and precipitation was below average for the majority of the month, despite a strong cold snap that hit the state just before Halloween. So far in November, eastern Colorado has experienced above average temperatures that are likely to continue, while several decent storms blanketed the mountains, resulting in average snowpack for this time of year in western Colorado. On November 30th, Governor Polis activated Phase 3 of the State Drought Mitigation and Response Plan along with a Municipal Water Impact Task Force to help water providers coordinate and prepare for a potential multi‐year drought.
A critically hot spring, high winds, dry summer, and multiple monsoon seasons with poor to no moisture have contributed to 2020’s record breaking fires. The three largest wildfires in Colorado history occurred in the summer and fall of 2020. Historically, Colorado’s largest wildfires occur in June following poor winter snowpack and an early springtime melt out. However, the Cameron Peak and East Troublesome fires experienced rapid and intense expansion in October ‐ a completely unprecedented phenomenon.
The Nov. 25 U.S. Drought Monitor logged 27% of the state in D4 (exceptional) drought conditions; D3 (extreme) drought in 47% of the state; D2 (severe) covering 19%; and D1 (moderate) drought covering 6% of the state.
The 90‐day Standardized Precipitation Index (SPI) (August 19 to Nov 16) values continue to show drier than normal conditions across the state.
The ENSO forecast predicts that moderate La Niña conditions will last through the winter. La Niña generally means an increase in moisture to the north and less to the south. Historically this pattern leads to snowier winters in the northern Rockies and less precipitation to the south.
The NOAA Climate Prediction Center three month outlook maps indicate an increased chance for above average temperatures over the winter with an equal chance (e.g. unclear trend) of precipitation.
Statewide reservoir storage is currently at 82% of average. Storage in the northern half of the state is near average while the southern basins range
Municipal water providers continue to report increased demands and most municipalities report normal to slightly below normal storage. Water providers are closely monitoring conditions due to the likelihood of extended drought to prepare for a dry spring.
From The Mountain Town News (Allen Best):
Colorado’s second biggest electrical utility will soon identify its path to 80% reduced emissions by 2030. Surely this map will include Arizona and Wyoming.
Tri-State Generation and Transmission last week promised to deliver what Colorado wants, an 80% reduction in carbon emissions by 2030. As for how it will deliver on that pledge, it remains a bit of a mystery.
Less coal production, obviously. More wind and solar, ditto. And, as has been highlighted in recent filings, more transmission to get electricity from renewable sources to its 16 member co-operatives in Colorado.
But how exactly?
For that, a more definitive answer will likely have to wait until Dec. 1 and perhaps beyond. That’s when Tri-State is scheduled to deliver an electric resource plan to state regulators. This plan is to explain in detail how it intends to procure electricity in coming years for its Colorado cooperatives. Colorado’s co-ops together account for about two-thirds of Tri-State’s demand across a four-state area.
Tri-State is Colorado’s second largest utility based on the amount of electricity it delivers in the state. In 2019 it delivered 38% as much electricity as compared to Xcel.
This electric resource plan will be a first for Tri-State. The utility has never been directly regulated by the Colorado Public Utilities Commission. SB 19-236, one of the many laws passed by Colorado legislators in 2019 to complement new economy wide carbon reduction targets adopted in the same session, makes it clear that the PUC has jurisdiction over Tri-State’s resource planning activities. A September filing by the Colorado PUC staff asserted that the “overriding concern” in evaluating Tri-State’s plan is how the utility “can meet Colorado’s emissions reduction cost effectively.”
Foundational to Colorado’s efforts to decarbonize its economy 50% by 2030, with even deeper cuts by mid-century, is removing carbon emissions from the electrical sector and then using electricity for other uses now fulfilled by fossil fuels in the transportation, industrial, and building sectors.
The 2019 legislation laid out an explicit requirement of 80% emissions reductions of Xcel Energy, which had by then agreed to do so. The state’s authority over other utilities, however, is more fuzzy.
In recent months, Will Toor, executive director of the Colorado Energy Office, has secured commitments from Platte River Power Authority, the wholesale provider for four municipalities along the Front Range, and also Colorado Springs Utilities. This commitment by Tri-State binds the overwhelming majority of Colorado electrical production to the emissions reductions identified by legislators.
A smaller utility, Holy Cross Energy, has adopted a more restrained goal of 70% by 2030 but is almost certain to hit that target within the next year.
Tri-State in January announced it would close the Escalante coal plant in New Mexico this year, which it did in September, and that it would have all the three units near Craig that it operates closed by 2030.
Still, Tri-State has a long, long way to go. Baseline modeling done by the utility in advance of its Dec. 1 filing showed a 34% reduction in Colorado in carbon dioxide emissions by 2030 as compared to a 2005 baseline.
Last week, after Tri-State’s announcement, Tri-Harder, a new coalition of Tri-State members, issued a statement. Speakers were cautious in their praise.
“Telluride can’t meet its carbon reduction goals unless Tri-State takes the lead on carbon reductions, so we’re thrilled with this news,” said Todd Brown, mayor pro-tem of Telluride. “I hope this means that Tri-State will invest in local, clean energy in our communities so that our local economies can benefit as well as the climate.”
Wyoming and Arizona
With Colorado Gov. Jared Polis rubbing virtual elbows, video-conference style, Tri-State chief executive Duane Highley took questions about his utility’s pathway.
Highley said the utility will be adding thousands of megawatts of new generating capacity in wind and solar and expects to be at 50% renewables across its entire system by 2023; in 2019 it was about 30%, about the same as Xcel.
But what will it do about imported power into Colorado? Tri-State imports power to meet needs of Colorado consumers from the Laramie River Station at Wheatland, Wyo., and from the Springerville 3 plant in Arizona. Tri-State is a minority owner in the Laramie River Plant but owns all the output from the unit at Springerville.
Highley said that Tri-State will diminish the power from the Wyoming plant over time, but did not give a time line.
The PUC staff report in September pointed out that aside from natural-gas generation, almost all the other carbon dioxide emissions in 2030 are from these out-of-state coal units.
“According to Tri-State, there are no provisions for modification or early termination” of the contracts” and Tri-State “has not analyzed such an action. The staff report went on to say that the resource planning review before the PUC “may include clear evidence that for Tri-State to meet its cumulative Colorado GHG reduction obligations, it cannot continue to serve Colorado load (demand) using those out-of-state resources.”
Tri-State, in an Oct. 2 filing, said it is developing several scenarios as part of its planning. “These scenarios will address the social cost of carbon on a system-wide basis, as well as specified carbon reduction goals in the state of Colorado,” the filing said. “These scenarios include aggressive levels of renewable energy additions and energy storage, allow for demand-side management, limit thermal additions, allow for retirement of existing resources, and incorporate either base or low-load forecast.”
What its load—the demand for its electricity—will be could be impacted by changes in the oil-and-gas sector, as Tri-State is a major supplier to oil-and-gas fields, but also the potential for existing cooperatives to leave or transition to partial requirements, Tri-State says.
In other words, there are a lot of uncertainties about just how much electricity Tri-State will need.
Another electric resource planning process will commence in 2023, not long after the current one is settled.
This is from the Nov. 20, 2020, issue of Big Pivots, which chronicles the great energy transition in Colorado and beyond. Sign up for copies at BigPivots.com.
Electric resource plans are wonky but rigorous things. Xcel Energy and Black Hills are required to file them. In addition to the filings of the utilities, laying out their plans and answering questions, intervening parties, including environmental groups, independent power producers, and the Office of Consumer Counsel, chip in statements, sometimes lengthy. Printing out all the filings in some of these cases can cost you a box of paper. The plans can drag on for years. Like painting the Golden Gate Bridge, the job is completed and then begins from the other side again.
The Tri-State filing will be a first for the utility itself. It will also be the first time for any resource plan since state legislators adopted the suite of energy laws in 2019. None was more expansive than SB 19-236, which reauthorized existence of the PUC but also delivered new criteria for how commissioners are to evaluate plans by utilities.
One example: The lengthy bill—it runs 64 pages—specifies that the commission must establish the cost of carbon dioxide emissions produced by electric generation resources, starting at not less than $46 per ton. The rate must be escalated based on the work by the federal interagency working group. This is called the social cost of carbon.
The PUC commissioners, at their weekly meeting on Nov. 12, ruled that Tri-State must use cost escalators in the models it submits for future electrical generation on Dec. 1.
Necessarily, the Colorado PUC will be examining Tri-State’s four-state operating system. Already, there are questions.
Reacting to Tri-State’s 80% announcement, Eric Frankowski, director of the Western Clean Energy Campaign, warned against any attempt to make this “an accounting exercise by shipping its expensive, dirty coal to its members outside of Colorado.”
Western Resource Advocates will also be watching carefully how Tri-State explains its accounting of greenhouse gas emissions in the review process.
Gwen Farnsworth, WRA’s senior energy policy advisor, says Tri-State’s announcement puts it at a better starting point for the electric resource plan in December as compared to the data provided by the utility earlier this year. That process before the PUC, she added, “provides a rigorous, evidence-based process to review Tri-State’s plan and emissions reductions claims.”
Tri-State’s cases will be different from the filing by Xcel Energy next March 1 in that the PUC has clear authority over setting rates in the case of Xcel. Tri-State sought oversight by the Federal Energy Regulatory Commission because it operates in four states.
One important area is that of transmission. Transmission has been constructed in a piecemeal fashion in Colorado over the decades. This new push for rapid development of renewable generation calls for a more unified and systematic approach to thinking about both new resources and transmission, instead of considering them separately.
Transmission was also the subject of Highley’s second significant announcement last week. He said Tri-State and four other power providers have sent letters committing to evaluate expansion of the Southwest Power Pool’s regional transmission organization, or RTO, into the West. The other utilities are Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, and the Western Area Power Administration.
In essence, Tri-State has assembled buddies to challenge the more dominant idea in Colorado that the most logical way to realize benefits of managed markets will be to join with the California and other utilities in the West. Like Tri-State, generation and transmission associations, the one larger and the other much smaller, MEAN is a public power provider of many Colorado towns and cities.
For a deeper dive on RTOs and EIMs and other wonky stuff considered by utilities crucial to achieve deep penetration of renewables electricity, see Lower electricity bills in Colorado, and also Why Colorado needs an RTO.
Tri-State and WAPA — the distributor of electricity generated by federal dams in the West— in September 2019 announced they were forming an energy imbalance market with the aid of the Arkansas-based Southwest Power Pool. Xcel Energy and three partners—Platte River Power, Black Hills Energy, and Colorado Springs Utilities—three months later said they were doing the same but with the aid of CAISO, the California-created operator.
Creation of these imbalance markets is seen as a low-risk, low-reward investment in coordinating supplies, especially low-cost renewables, to meet demands. Highley has said that Tri-State can earn back its investment within three years. The far greater benefits will be found in an RTO.
A recent study by Vibrant Clean Energy found that a regional transmission organization, whether operated by SPP or by CAISO, could greatly benefit Colorado consumers, but concluded that the somewhat greater benefits were to be found with the alliance with California.
Asked about that study, Highley disagreed with the conclusion about CAISO but also said that whatever the regional alignment, there will be benefits of integrated transmission and scheduling to share wind, solar, and other resources across broader regions.
Allen Best is a Colorado-based journalist who publishes an e-magazine called Big Pivots. Reach him at firstname.lastname@example.org or 303.463.8630.
From The High Country News [November 26, 2020] (Jonathan Thompson):
In September, President Donald Trump visited fire-ravaged California and declared that the wildfires that had already burned across millions of acres were the result of forest mismanagement, not a warming climate. “When trees fall down after a short period of time, they become very dry — really like a matchstick. No more water pouring through, and they can explode,” he said. “Also leaves. When you have dried leaves on the ground, it’s just fuel for the fires.”
Trump is right about one thing: Global warming isn’t the only reason the West is burning. The growing number of people in the woods has increased the likelihood of human-caused ignitions, while more than a century of aggressive fire suppression has contributed to the fires’ severity. In addition, unchecked development in fire-prone areas has resulted in greater loss of life and property.
Yet, much as California Gov. Gavin Newsom told Trump, it’s impossible to deny the role a warming planet plays in today’s blazes. “Something’s happening to the plumbing of the world,” Newsom said. “And we come from a perspective, humbly, where we submit the science is in and observed evidence is self-evident that climate change is real, and that is exacerbating this.”
The accompanying graphic includes a few examples of the evidence Newsom mentioned. But then, you only have to step outside for a moment and feel the scorching heat, witness the dwindling streams, and choke on the omnipresent smoke to know that something’s way off-kilter, climate-wise.
But during his September stop outside Sacramento, California, under a blanket of smoke, Trump merely grinned and shrugged it off, again asserting that scientists don’t know what’s happening with the climate. And, anyway, he said: “It’ll start getting cooler. You just watch.”
Jonathan Thompson is a contributing editor at High Country News. He is the author of River of Lost Souls: The Science, Politics and Greed Behind the Gold King Mine Disaster. Email him at email@example.com
From The Grand Junction Daily Sentinel (Dennis Webb):
State water officials are hoping early next year to roll out a draft demand management proposal to help in evaluating the concept as a possible response to managing Colorado River water supplies in times of drought.
Creating a framework of what the program could look like isn’t meant to tie hands and say what the Colorado Water Conservation Board thinks it should look like, CWCB staff member Amy Ostdiek told the board in its meeting earlier this month. Rather, it’s aimed at giving everyone involved the ability to have something to respond to, with the hope of perhaps creating a better draft or a new concept, she said…
The CWCB, which sets state water policy, says demand management would involve temporary, voluntary and compensated reductions in consumptive use of Colorado River Basin water. This is expected to entail use reductions in municipal, agricultural and other uses, with agricultural cuts resulting from measures such as short-term fallowing of fields.
The idea is drawing particular scrutiny from entities such as the Western Slope’s Colorado River District due to concerns about potential economic impacts on agriculture-based communities. A recent study commissioned by a work group including the district found that the secondary economic impacts of paying western Colorado farmers to temporarily fallow fields could be similar to the secondary benefits from the spending of those payments. But it said the dollars from payment spending would flow to different businesses, perhaps shifting to larger towns and cities from smaller, ag-based towns.
Among other criteria for going forward, a demand management program would have to be found to be feasible by every Upper Basin state. This means looking at things such as availability of funding, whether a program would comply with state and federal laws, how it would be administered, etc.
The CWCB began evaluating the concept by establishing work groups involving experts and stakeholders from around the state looking at issues surrounding demand management.
With their input now in hand, the agency is taking the next step in investigating the concept. That will entail considering if it is achievable in terms of things such as funding, worthwhile when it comes to questions such as how much water would be stored, and ultimately advisable to pursue in Colorado.
CWCB plans to continue its evaluation in a public, collaborative way, involving water users, tribal entities, nongovernment organizations and other stakeholders in commenting on the draft proposal, Ostdiek said.
Becky Mitchell, the CWCB’s director, told the board at its meeting that fires and drought affected every Coloradan this year.
She said that with the climate changing and drought becoming more frequent and intense, it would be irresponsible for the CWCB not to look at every tool available to respond, including demand management.
Here’s the release from the Colorado Water Conservation Board:
As severe drought conditions have persisted across 100% of Colorado for over 15 weeks, Governor Jared Polis directed a shift from Phase 2 to Phase 3 (full activation) of the State Drought Mitigation and Response Plan.
This includes convening the Municipal Water Impact Task Force, chaired by staff from the Colorado Water Conservation Board (CWCB) and Department of Local Affairs, with the objective of coordinating with water providers to prepare for anticipated drought-related challenges well into 2021.
“Now with three drought task forces activated going into the winter season, the state will have time to coordinate with agriculture, municipal, and other sectors across the state to develop a plan for mitigation of drought-related impacts starting in spring of 2021,” said CWCB Director Rebecca Mitchell. “Climate outlooks for 2021 indicate that drought conditions are likely to continue into the next year, so it is important that we are proactively thinking about mitigation and that we remain hopeful for strong winter snowpack statewide.”
The Municipal Water Task Force will join the Drought Task Force and the Agricultural Impact Task Force, which were activated in June. Drought condition summaries are released monthly from water and climate specialists on the Water Availability Task Force.
Colorado Departments of Agriculture and Natural Resources are seeking public input about drought impacts in communities across the state. Submit personal and local accounts of drought, including agricultural impacts, on the Virtual Drought Tour platform.
For updates and background on Colorado drought, visit the CWCB website.