The Cheyenne Ridge Project and the Story of My Career

I got started in energy law working for Environment Colorado in 2004, where I led the organization into the PUC breach to contest a new coal-fired power plant that was proposed in 2004.  After that banner year for me - which also included passage of Colorado’s Renewable Energy Standard, I started working at a water law firm.  About two years later I got a call from Matt Jacobs, someone I didn’t know.  He had heard my name from Ron Lehr, one of the leaders in the Colorado electric space whom I had collaborated with while working at Environment Colorado.   Matt had a start-up wind development company called EnCompass.  Having virtually no experience in business and only some exposure to utilities law, I jumped at the chance to work on a wind lease.  So I gathered every able body I could at my firm with any remote connection to energy or land issues into my first meeting with Matt, found a CLE on the subject, and fumbled my way through the meeting. It worked!   I was hired to work on a wind project.

    We had gotten a draft wind lease put together after a few months, when Matt was whisked away by Tradewind Energy.  As my luck would have it, Matt brought me along with him to work on a Colorado project.  Matt was sure he had identified the windiest site in Colorado for Tradewind.  The land was located about 20 miles south of Burlington, Colorado, right on the Kansas border where the wind regime was more like Kansas than Colorado.  It had expansive terrain, incredible and consistent wind speeds, and the Eastern Plains Transmission Project, a high voltage transmission line designed by Tri-State Generation and Transmission Association to bring coal power from its proposed plant in Holcomb, Kansas to Colorado, was proposed to run right through the center of the project.   It was called the Cheyenne Ridge Project.

    But soon after, in 2008, the Holcomb plant was rejected by Kansas Governor Kathleen Sebelius, who later would go on to head up the drafting and passage of the Affordable Care Act under President Obama.  The decision was a striking display of political courage in a state where every democrat in office is a short-timer from their inauguration.   Not long after the fall of Holcomb, Tri-State shelved the Eastern Plains Transmission Project (“EPTP”).  The Cheyenne Ridge Project was hung out to dry. 

    There was only one transmission line close to the project, and that was a medium voltage line owned by Tri-State, who at the time was decidedly not interested in buying wind power.  The only real buyer was Xcel Energy, who had started its first wind acquisitions for Colorado’s renewable energy standard in 2006.   And there was no transmission solution to reach Xcel’s load without the EPTP. 

    The Cheyenne Ridge Project tasked me with figuring out a transmission solution for its project.  At this job, I largely failed.   Each year, the utilities would discuss, even study, sometimes for years, proposed big transmission projects like the High Plains Express or the Lamar to Front Range.  But each time a decision got close, the football was pulled.  As a result, transmission was always right around the bend, but never in sight.

    My task ran into the brick wall constructed by the transmission-providing utilities in Colorado, who guard their transmission kingdom jealously.  Since the passage of PURPA, utilities have slowly lost ground in their control of access to the transmission system, and in the process surrendered parts of their monopoly control.  Transmission planning is one remaining bastion, however, allowing the utilities effective control over the development of their systems.  Without transmission access, independent power producers ("IPPs") have nothing.

    Over the next ten years I worked on this project with Matt and then other project managers.   Sometimes we were fighting both internally and externally to keep the project going.  Through this work, I became involved in the wind industry, and that led me further into utilities law.  After representing Tradewind as a member of a trade group for several years, I was lucky to find myself asked to represent that group.  I was hired by other IPPs based on the experience I gained with Tradewind, and eventually found myself with an adequate amount of experience to keep going.  And Matt and I became great friends, attending pitch after pitch with utilities.

     Things changed in 2016 when Xcel made the leap into the wind business.  It purchased the Rush Creek project.   The project was not exactly the neighbor of Cheyenne Ridge, but it was in the neighborhood.  Because there was no transmission to the area, Xcel made the move to build a giant extension cord, the Rush Creek line, some 96 miles east into the windiest area of Colorado, and twenty miles south of Burlington, to access its project.  It was as close to a knock at the front door Cheyenne Ridge had seen since the EPTP.   

    Xcel then filed its 2016 Electric Resource Plan.  It noted that bids would be accepted on the Rush Creek line, and the Rush Creek line was going to draw the most attention in the state, again because of the lack of transmission anywhere else.  Soon after that, the Colorado Energy Plan was announced, and suddenly the resource need was gigantic. 

    And Matt was right, the Cheyenne Ridge Project was the windiest site in Colorado.  With transmission now available, it was the site Xcel selected for itself.  And last week, in April 2019 and over ten years after Matt walked into the office of a rather green lawyer (pun intended), the PUC approved the Cheyenne Ridge Project.  If I am luckier still, I will be there to help break ground for the project that helped break so much ground for me.

Submitted By: Mark Detsky

The Colorado Energy Plan and the Far Side of the Rubicon River

The phrase “Cross the Rubicon” is a reference to the ultimatum that the Roman Senate delivered to Julius Caesar not to bring his army across the Rubicon River.  When Caesar ignored that warning, the period of imperial Rome had begun.  Thus, to cross the rubicon has come to signify a decision point from which there is no turning back.  The nature of the analysis is such that the rubicon is usually only able to be seen in hindsight.  This is not so in the electric generation sector (in Colorado at least).  We are so far past the rubicon where renewable energy resources have outpaced the large coal-fired generation that dominated the 20th century that we can review the next big decision in Colorado energy policy as logical today to what was once only a “pipe dream” (a story for another day).  That decision point is known as the Colorado Energy Plan (CEP).

The CEP is an offshoot or add-on to the pending Electric Resource Plan (ERP) process of Public Service Company of Colorado (dba Xcel Energy) currently before the Colorado Public Utilities Commission.  ERPs occur every 4 years; though this current plan dates back to October 2015 (when it was first due).   Xcel serves approximately 65% of Colorado territory and, with over 1.2 million customers and approximately 7000 megawatts (MW) of demand on its system, is the largest utility by load as well.  The CEP would result in the early retirement (by 10 years) of the Comanche 1 and 2 coal-fired generation units.  These units have a capacity of about 660 MW.  The CEP would replace that capacity, along with 450 MW of load-related resource need, with a plan including a range approximating 1000 MW of wind, 600 MW of solar, and 600 MW of natural gas-fired units.  

The CEP has a number of associated parts.  There is a utility ownership target that independent power groups such as our client the Colorado Independent Energy Association (CIEA) negotiated in the settlement agreement that brought forward the CEP.  The targets are a range of 40 – 60 percent for renewables and 60 -75 percent for gas units.  The coal-fired units will have their remaining amortized capital costs paid off by reducing the revenue stream intended for renewable energy’s incremental costs, known as the “RESA”.  The RESA collects 2% of customer bills to pay for the incremental system costs for acquiring renewable resources.  For large-scale renewable resources, there no longer is any incremental cost because those resources these days cause overall system cost savings.  So, a cut for the RESA to pay down call redirects revenues to a similar purpose.  There are also transmission elements to the plan. 

The CEP has been bolstered by the remarkably low cost proposals for wind, solar, and energy storage that Xcel received in its solicitation for the ERP from independent power producers (IPPs).  The median price of the wind bids is less than 2 cents per kilowatt (kW) of capacity, and less than 3 cents/kW for solar capacity.  These prices have not before been seen in Colorado or much of the world for that matter.  In addition, Xcel is seeking to join the Southwest Power Pool market, where units are dispatched by an objective third party and not by each utility. Simultaneously, Xcel has taken notice that in areas of the country with established markets, coal plants are either retiring or sitting idle as uncompetitive.

The value of the bid prices received has allowed Xcel to focus its CEP case to the Public Utilities Commission on straight economics, before reaching the environmental benefits or market risks.  This process has allowed consumer groups and large industrial customers to support bringing the CEP forward.  But this analysis, of course, misses the point.  The CEP would not exist but for the urgent need to mitigate human contributions to climate change.   The costs of inaction on climate change dwarf any economic analysis on rate impacts when you consider that our functioning ecosystem is what allows our economy to exist.

The CEP is not the first coal retirement plan, even in Colorado.  Coal plants are being retired – or stranded – across the country also due to economics. The costs of using fossil fuels and mitigating the resulting emissions cannot compete against smaller plants that use natural gas or no fuel at all.  In 2010, Colorado passed the Clean Air Clean Jobs Act (CACJA), that retired approximately 900 MW of Xcel-owned coal-fired generation.  In that case, the tension between fossil fuel and renewables was at its zenith. The coal industry was still fighting back with traditional arguments at the PUC and in the courts.  When the CACJA was approved, the implementation of that statute was the march across the Rubicon River.

But today those days are behind us.  The paradigm shift has occurred.  The coal industry at the February 2018 CEP hearing solely debated the modeling and the accounting mechanism to recover the retirement of the Comanche 1 and 2 Units, even though there is no allowance for overall bill increases to accomplish the CEP.  When anything other than ratepayer bills are considered in the analysis, the competition isn’t even close.  This is not good news in the near term for regions that depend on a coal economy, but it is overall the best news for humanity.  The CEP is what life is like when the rubicon has been crossed, and the future that was envisioned decades ago for a renewable generation portfolio using natural gas as a “bridge fuel” has actually arrived.  Renewable technologies were given the opportunity to prove their worth, and they have met that challenge.  For the coal industry, Rome lies ahead.

Submitted by: Mark D. Detsky

Some Highlights from the October 2017 Commissioners’ Information Meeting on the Mountain West Transmission Group

On October 20, 2017, the Colorado Public Utilities Commission (“PUC”) held a Commission Information Meeting regarding the application of the Mountain West Transmission Group (“MWTG”) to join the Southwest Power Pool (“SPP”). This meeting covered an overview of the SPP and the MWTG, the transmission planning process, the SPP process related to integrating new members as well as to modifying SPP governing documents, and the projected timeline and next steps for the process.

The MWTG is a coalition of 10 electricity service providers with about 6.4 million customers and 16,000 miles of transmission lines in, mostly in the Rocky Mountain region.  It includes Basin Electric Power Cooperative, Black Hills Energy, Colorado Springs Utilities, Public Service Co. of Colorado, and Tri-State Generation and Transmission Association. Xcel Energy's Denver operation is also a member.

MWTG formed and began discussion on the creation of a Regional Transmission Organization (“RTO”) in 2013.  Among the many options considered—from joining another RTO to the creation of their own—the members generated the most consensus on joining the SPP.  The organizations are now in the process of integrating Mountain West into the SPP as well as applying for approval of the integration with the appropriate state and federal entities.

                                                                 MWTG-SPP Footprint

Presenters highlighted the 5 phases of integration: (1) initial discussions, (2) due diligence and membership agreement discussions, (3) open-access transmission (“OAT”) tariff negotiations (which includes proposal and modification of governing documents like bylaws), (4) FERC and state approval, and (5) actual integration. The parties are now engaged in phase (2) and (3), which is has been slow between the 95 SPP stakeholders.  MWTG and SPP have set a tentative date for full integration by October 2019.  They also referenced the website created to provide information on the integration process and briefly outlined how members, customers, market participants or regulators could submit questions, commentary, and suggested revisions to the tariffs and governing documents.

Members of SPP and MWTG also presented an outline of the proposed transmission plan. They first explained “pancake pricing,” and the consequences of eliminating pancakes in an RTO. Pancake pricing occurs when a transmission customer is charged separate access charges for each utility service territory crossed by the transmission customer's power transaction. “Pancaking” increases the price of electricity and discourages competition in the generation sector. By combining transmission systems under a single RTO like the SPP, a wider area served by a single rate can be designed, thus eliminating pancakes. However, this elimination will generate cost-shifts across the MWTG region, and the parties are still negotiating the terms of the agreement around mitigation of these cost-shifts.

The presenters also emphasized that under the SPP, project selection will alter to consider a broader scope of benefit.  While local planning will remain important, SPP will also perform a regional evaluation (for the east and west, respectively) of each proposed project to determine their overall costs and benefits to that region. Thus, a project that has a large benefit locally, but little benefit regionally, may not be approved under SPP protocols when compared to a project with less local benefit but a greater overall benefit. The SPP will also introduce a new model for cost allocations of such projects as well, which will scale costs related to local and regional benefits and project size. The parties continue to negotiate on the details, but the presenters assured that the project selection and cost allocation processes will not include those projects that are necessary to ensure transmission reliability in the region.

The parties also discussed governance models under the SPP. MWTG’s primary change to the SPP model would be to include more seats on the boards and working groups so that Colorado’s west slope would be adequately represented in the decision-making process. For example, certain deal terms would require consent from western transmission owners by majority vote before they could be changed, and western transmission owners would have more input on proposals that would alter the nature of the RTO.

Representatives also presented on the upcoming regulatory issues related to FERC and state filing of MWTG’s application to join the SPP.  The projected filing deadlines were all based the October 2019 integration rate. Given the importance of the FERC process and its potential to confront and resolve application issues that would arise at the state level, the MWTG decided to file with FERC first before going to the state, so that the federal processes and outcomes could be incorporated into the state filing. The MWTG mentioned that its discussions with FERC are still mostly informational, but that this filing will be one of the most significant to come to FERC in recent memory due to its size and its multi-jurisdictional aspects. FERC has expressed preliminary concerns with the transition process as well as its ability to issue compliance orders to the SPP. 

MWTG closed by highlighting their bottom line: despite the costs, the process represents a diverse and broad perspective of entities seeking integration, which demonstrates its value.  MWTG also identified its next steps: namely, the filing processes with the FERC, future meetings related to the integration and its ability to uphold Colorado’s constitutional mandate to expand renewable energy, and the state and the issuance of a detailed cost-benefit analysis.

Much of the integration process remains in its planning stages, and the information provided here is also subject to change as the parties continue negotiations and formalize their filings for both FERC and the PUC. However, a number of up-to-date resources are available, listed below:

The Mountain West Transmission Group Initiative

The October 2017 Information Session Presentation  

SPP-MWTG Stakeholder Package

Submitted by: Rebecca Boyle