Table of Contents<\/p>\n
Introduction<\/p>\n
I. Background: U.S. Energy Markets and Colorado Senate Bill 72<\/p>\n
A. Electric Utility Regulation and Energy Markets in the United States<\/p>\n
B. Electric Utility Regulation and Energy Markets in Colorado and the West<\/p>\n
C. Overview of Senate Bill 72<\/p>\n
1. Organized Wholesale Market Requirement<\/p>\n
2. Creation of the Colorado Electric Transmission Authority<\/p>\n
II. Motivations and Impact of Senate Bill 72 and Stakeholder Responses<\/p>\n
A. Motivations and Impacts of Senate Bill 72<\/p>\n
1. Improving Grid Reliability and Resilience Through the CETA<\/p>\n
2. Expanded Wholesale Generation Resource Base and Resource Adequacy<\/p>\n
3. Meeting Colorado\u2019s Climate Goals<\/p>\n
4. Economic Motivations<\/p>\n
B. Key Stakeholder Responses<\/p>\n
1. Xcel\u2019s Pre-Bill 72 Progress and Response to Proposed Legislation<\/p>\n
2. Colorado PUC Response<\/p>\n
III. Potential OWM Targets and Western Progress on OWM Participation<\/p>\n
A. Overview and Potential OWM Targets: CAISO, SPP, or a new West-wide RTO<\/p>\n
B. OWM Progress by Western States: Nevada, Utah, and California<\/p>\n
IV. Potential Drawbacks and Shortcomings of Senate Bill 72<\/p>\n
A. Existing Barriers to Transmission Buildout Will Continue<\/p>\n
B. Loss of Local Price Signals<\/p>\n
C. Dependency on Market Footprint and the OWM Opt-Out Provision<\/p>\n
D. Loss of Regulatory Autonomy<\/p>\n
Conclusion<\/p>\n
<\/a><\/a> Introduction<\/p>\n In the summer of 2021, the Colorado Senate enacted Bill 72\u2014a law that will significantly shift the wholesale energy market in Colorado and possibly the entire western United States.[2]<\/a><\/sup> Bill 72 mandates Colorado transmission utilities to join, by 2030, a wholesale electricity market in the region that \u201ccoordinat[es] and efficiently manag[es] the dispatch and transmission of electricity among public utilities on a multistate or regional basis<\/em>.\u201d[3]<\/a><\/sup> This requirement will affect both the process and objectives of key electricity decisions made at the state and regional level, changing the way Colorado plans transmission and ensures resource adequacy for its grid.[4]<\/a><\/sup> Whatever form this new market takes, Colorado has acted definitively with Bill 72 by opening its wholesale electricity regime to a multi-state marketplace, promising increased resource optimization and reliability, and an abundance of new, clean energy sources available at lower costs. Under Bill 72, Colorado and the West will be better able to plan regional transmission lines and to connect remote supply resources (such as desert solar) to populated areas with the highest electricity demand. In short, Bill 72 is an opportunity to \u201cunlock\u201d the fractured electricity transmission planning process in the West, connecting Colorado\u2019s electricity market to the rest of the region.<\/p>\n At the same time, Colorado has already instituted useful governance practices that may not be replicable at the regional level. And existing organized wholesale markets are not without risks and shortcomings. Nonetheless, if other western states join Colorado in regional wholesale market participation, the most optimized form of such a market structure will generate great benefits for utilities and ratepayers alike.<\/p>\n This Note argues that despite the potential loss of some regulatory autonomy in Colorado and the pitfalls and limitations of existing regional markets, Bill 72 manages to address existing limitations in transmission planning in the state; puts the entire region on a path towards lower energy costs and reduced carbon emissions by connecting Colorado with the rest of the West; and \u201cunlocks\u201d its grid by increasing transmission capacity across the region. Despite the progress made by Colorado transmission utilities on infrastructure planning, renewable energy adoption, and participation in more limited wholesale energy markets, this Note contends that an Organized Wholesale Market with a transmission planning mechanism better addresses transmission planning challenges, resource adequacy optimization, and increased renewable energy adoption.<\/p>\n One key to Bill 72\u2019s expected success hinges on the ability of a new centralized transmission planning authority to identify regional transmission corridors and leverage a more streamlined regulatory approval process. Relatedly, Colorado and the West must accelerate the adoption of renewable energy resources and quickly address the climate crisis. By opening itself up to more generation assets in other energy markets, Colorado will not only make significant progress towards these goals but also help lead the<\/em> West<\/em> on regional climate progress. Indeed, momentum is building towards West-wide participation in a wholesale energy market that includes transmission-planning services. Colorado has pushed the snowball down the hill with this new legislation.<\/p>\n This Note will first review the background of energy market structures in the United States. It will then review the key elements of Colorado Senate Bill 72 that will transform the wholesale energy market in Colorado, as well as the motivations, consequences, and key stakeholder responses to the legislation. Because of the benefits to be gained by West-wide participation in an Organized Wholesale Market, this Note highlights existing market options and the progress other Western states have made or are planning in this area. The final Section provides an analysis of the concerns and potential drawbacks of the legislation.<\/p>\n <\/p>\n I. Background: U.S. Energy Markets and Colorado Senate Bill 72<\/p>\n <\/a><\/a> A. Electric Utility Regulation and Energy Markets in the United States<\/p>\n Electricity markets operate at both the retail level and wholesale level. On the latter, \u201cload-serving\u201d entities buy power to resell on the retail market to electricity ratepayers, such as residential, commercial, and industrial energy users.<\/a>[5]<\/a><\/sup> Although Bill 72 and this Note concern wholesale <\/em>electricity markets, changes at the wholesale level will impact retail electricity customers; therefore, it is necessary to outline how energy markets are designed and regulated in the United States and Colorado.[6]<\/a><\/sup><\/p>\n Load-serving entities are often structured as investor-owned electric utilities, or \u201cIOUs,\u201d which serve most electricity customers in the United States. <\/a>[7]<\/a><\/sup> About one-third of IOUs in the country operate as state-sanctioned monopolies.[8]<\/a><\/sup> These IOUs participate in so-called \u201cregulated\u201d electricity markets, where state utilities commissions, such as the Colorado Public Utilities Commission (\u201cPUC\u201d), directly regulate the load-serving IOUs.[9]<\/a><\/sup> The most important aspect of this relationship is that the PUC approves the price at which electricity rates are set for customers, who can buy power from the regulated IOU only.[10]<\/a><\/sup> Given the capital-intensive nature of electricity generation and distribution, these regulated monopolies receive a guaranteed rate of return on investments such as power plants, transmission lines, and distribution infrastructure.<\/a>[11]<\/a><\/sup> Importantly, because the costs and rate of return on investment are borne by ratepayers, the state PUC ensures that electricity rates are fair and justified for both the IOU (looking to recover its costs and to incentivize future investment) and ratepayers (looking to keep rates as low as possible without sacrificing reliability).[12]<\/a><\/sup><\/p>\n But IOUs can and do operate in both regulated and \u201cderegulated\u201d markets or, perhaps more helpfully named, \u201crestructured\u201d markets. In regulated markets, IOUs are \u201cvertically integrated,\u201d meaning they \u201cown or control the total flow of electricity from generation to meter.\u201d[13]<\/a><\/sup> This is the case in Colorado.[14]<\/a><\/sup> In contrast, a fully restructured energy market generally implies that the IOU has (functionally or physically) \u201cunbundled,\u201d or separated, its generation assets from its distribution business and that the state has introduced generation and supply competition into wholesale generation and retail load-serving markets.[15]<\/a><\/sup> In such a scenario, the IOU retains its monopoly over the physical wires that distribute electricity to customers but ratepayers have the ability to choose their retail electricity supplier, at least in theory.[16]<\/a><\/sup><\/p>\n Of course, the distinction between \u201cregulated\u201d and \u201cderegulated\u201d \u00ad(or restructured) electricity markets is not so black and white. For one, regulated IOUs with a retail monopoly may participate in competitive wholesale<\/em> markets (e.g., purchasing competitively priced electricity for resale on an Organized Wholesale Market (\u201cOWM\u201d)). Likewise, utilities in so-called deregulated or restructured retail markets will still be subject to state regulation, i.e., for the retail rates related to their distribution<\/em> monopoly on the physical wires serving homes and businesses.<\/p>\n Utility restructuring (at both the wholesale and retail levels) took hold in the 1990s in the Northeast, Mid-Atlantic, and the Midwest.[17]<\/a><\/sup> These market constructs naturally lent themselves to the creation of and participation in OWMs, such as the New England Independent State Operator, the Midcontinent Independent State Operator (\u201cMISO\u201d), the Southwest Power Pool (\u201cSPP\u201d), and PJM.[18]<\/a><\/sup> OWMs (and other types of wholesale structures, such as \u201cimbalance\u201d markets) effectively operate as federally-regulated auctions, which allow multiple electricity suppliers to bid <\/em>into the market in order to offer a certain amount of energy supply at a given price, while \u201cload-serving entities,\u201d such as IOUs, ask <\/em>for certain amounts of energy in order to meet predicted electricity demand.[19]<\/a><\/sup> In such markets, once demand is satisfied, the market \u201cclears\u201d at the last price offered by electricity suppliers (and all suppliers receive that price for their supply).[20]<\/a><\/sup> These markets are commonly subdivided into day-ahead bidding markets (making up ninety-five percent of energy transactions in the United States) and real-time bidding markets, which typically operate at one-hour intervals and fifteen-minute intervals to account for unforeseen changes in energy demand throughout a given day.[21]<\/a><\/sup> However, unlike a basic \u201cimbalance\u201d markets, OWMs typically include a coordinated transmission planning component.[22]<\/a><\/sup><\/p>\n OWMs are organized into what is called a Regional Transmission Organization (\u201cRTO\u201d), such as the SPP, or an Independent State Operator (\u201cISO\u201d), such as the California Independent State Operator (\u201cCAISO\u201d).[23]<\/a><\/sup> For example, the nearest OWM to Colorado is the SPP RTO, which operates from North Dakota down to Oklahoma and parts of Texas.<\/a>[24]<\/a><\/sup> The SPP exists on the Eastern Interconnection, connected by only seven high-voltage transmission lines to the Western Interconnection where Colorado sits.[25]<\/a><\/sup> However, the SPP is working to develop an extension of its RTO on the Western Interconnection and currently partners with some Colorado utilities in more limited market capacities.<\/a>[26]<\/a><\/sup> Although no West-wide RTO exists, this type of market structure serves two-thirds of the country\u2019s electricity load.[27]<\/a><\/sup><\/p>\n An OWM spreads capacity requirements across several suppliers, rather than a single utility, and likewise gives independent power producers (\u201cIPPs\u201d) access to a much larger base of potential customers, namely load-serving entities such as Xcel in Colorado.<\/a>[28]<\/a><\/sup> Per the Colorado PUC, \u201c[a]n RTO .\u00a0.\u00a0. consolidates reliability obligations, transmission planning, and cost allocation, and transfers functional control of the transmission system to the system operator.\u201d[29]<\/a><\/sup> For example, some generation assets, such as natural gas plants, sit unused for all but the highest demand (i.e., hottest) days of the year. [30]<\/a><\/sup> By tapping into the increased generation base across the West, Colorado might not require investment in as many costly, dispatchable peak generation plants. And through its central control of the market, an OWM operator can optimize energy flow so that its system\u2019s transmission availability is utilized to its full reliability limit.[31]<\/a><\/sup> As a result, with the complete picture of regional transmission capacity in view, OWM operators ensure that electricity is efficiently distributed to load-serving entities.<\/p>\n <\/a><\/a> B. Electric Utility Regulation and Energy Markets in Colorado and the West<\/p>\n Among other important provisions, Colorado Senate Bill 72 (\u201cBill 72\u201d) includes two key changes that will dramatically affect how Colorado transmission utilities interact with wholesale energy markets in the West: The Organized Wholesale Market requirement and the creation of the Colorado Electric Transmission Authority (\u201cCETA\u201d).[32]<\/a><\/sup> Specifically, Bill 72 requires any utility in Colorado that owns and controls transmission facilities to join an OWM by 2030.[33]<\/a><\/sup> In the name of fulfilling its stated goal of expanding \u201celectric transmission facilities to enable Colorado to meet its clean energy goals,\u201d Bill 72 will effectively introduce competition and regional coordination (e.g., on transmission planning) to the western wholesale markets in which Colorado utilities participate.[34]<\/a><\/sup><\/p>\n In addition to twenty-nine not-for-profit, municipally-owned utilities and twenty-two not-for-profit rural electric cooperative utilities, Colorado is served by two regulated IOUs\u2014Xcel Energy (doing business as \u201cPublic Service Company of Colorado\u201d) and Black Hills Energy.[35]<\/a><\/sup> Xcel is the largest electric utility in Colorado, providing service to 1.5 million customers in the state, including the Denver metro region.[36]<\/a><\/sup> In total, Xcel is responsible for about fifty-three percent of retail electricity sold in Colorado (to residential, commercial, and industrial customers), while Black Hills accounts for about four percent of such sales and serves about 100,000 customers in Pueblo and other communities.[37]<\/a><\/sup> As regulated monopolies, Xcel and Black Hills are granted a \u201cCertificate of Public Convenience and Necessity\u201d by the state PUC, giving each exclusive access to particular service territories.[38]<\/a><\/sup><\/p>\n Xcel and other Colorado utilities already participate in wholesale energy imbalance markets (\u201cEIMs\u201d), which operate similarly to OWMs but without a mechanism to plan regional transmission projects<\/a>.<\/a>[39]<\/a><\/sup> Although these markets help match supply and demand across a regional footprint, they require fewer commitments from participants and do not fully address the inefficiency that results from fragmented transmission control and planning in a decentralized system.<\/a>[40]<\/a><\/sup> California, for example, operates a regional EIM that engages in little transmission planning outside of the state.[41]<\/a><\/sup> As of this writing, there are no truly regional RTOs operating west of Colorado.[42]<\/a><\/sup><\/p>\n In addition to EIMs, many IOUs engage in \u201cbilateral\u201d wholesale markets, trading electricity directly with other utilities when needed.[43]<\/a><\/sup> But bilateral agreements are inherently limited and poorly integrate intermittent resources, such as wind and solar power, because of the fixed nature of such agreements and the limited number of \u201cmarket\u201d participants that could otherwise increase competition and reduce market clearing prices.<\/a>[44]<\/a><\/sup> For example, because of the intermittency of wind and solar resources (absent storage capacity), a larger market is more likely to match wind and solar supply with demand. Furthermore, although there are many EIMs and bilateral agreements between various utilities across the West, there is limited coordination between<\/em> these distinct EIMs and bilateral agreements. <\/a>[45]<\/a><\/sup> Therefore, putting aside even the potential benefits from regionally focused transmission planning, the West is not operating as efficiently as it might from a market perspective alone.<\/a>[46]<\/a><\/sup><\/p>\n With Bill 72, Colorado is one of only two Western states to fully commit to OWM participation, as of this writing.[47]<\/a><\/sup> The move will significantly shift the region\u2019s wholesale energy market regime and signal to the West that the state is prepared to engage in regional decision-making related to transmission planning, resource adequacy, and renewables adoption. The 2030 statutory deadline will allow Colorado to work with other states on the best OWM solution for the region, including getting ahead of and addressing risks and drawbacks with existing RTOs.<\/p>\n <\/a><\/a> C. Overview of Senate Bill 72<\/p>\n Bill 72, enacted in the summer of 2021, will require any transmission-owning and -controlling utility in Colorado (such as Xcel) to join an OWM by 2030.[48]<\/a><\/sup> Although Xcel has participated in EIMs, Bill 72 will significantly deepen Colorado\u2019s participation in regional wholesale markets. Specifically, the transmission-planning requirement of the OWM will help Colorado and the West reap the full benefits of regional coordination. Relatedly, Bill 72 creates a new independent transmission-planning entity, the Colorado Electric Transmission Authority.[49]<\/a><\/sup> The OWM requirement and the creation of CETA are the two most impactful changes from this bill, as outlined below.<\/p>\n <\/a><\/a> 1. Organized Wholesale Market Requirement<\/p>\n Under the new law, any \u201ctransmission utility\u201d (a utility that owns and controls at least one transmission facility) must join an OWM by the year 2030.[50]<\/a><\/sup> Bill 72 defines an OWM as a Federal Energy Regulatory Commission (\u201cFERC\u201d) approved RTO or ISO, \u201cestablished for the purpose of coordinating and efficiently managing the dispatch and transmission of electricity among public utilities on a multistate or regional basis.\u201d[51]<\/a><\/sup> Bill 72 further mandates that the OWM \u201c[e]ffects separate control of transmission facilities from control of generation facilities\u201d and must itself operate independently of any transmission ownership.[52]<\/a><\/sup> This requirement means that the OWM and generation participants would have neutral positions with regards to new transmission infrastructure projects, so long as such projects facilitate an efficient market.<\/p>\n Moreover, utilities cannot simply check the box: the target OWM must be of \u201csufficient scope\u201d or operational size to \u201cincrease economical supply [of electricity] options for customers.\u201d[53]<\/a><\/sup> Thus, joining an EIM that lacks a transmission planning component, or the full range of market capabilities, would not satisfy Bill 72. Lastly, in addition to regional goals, Bill 72 requires that the OWM, \u201c[i]mproves, to the extent possible, service reliability within Colorado.\u201d[54]<\/a><\/sup><\/p>\n Of course, there are off-ramps: if a transmission utility cannot, despite making \u201call reasonable efforts,\u201d find a \u201cviable and available\u201d OWM, the Colorado PUC may delay or waive the OWM requirement for that utility.[55]<\/a><\/sup> In such a case, the PUC must also find that it is not in the \u201cpublic interest\u201d for the transmission utility to join an OWM, considering factors such as whether the targeted OWM has sufficient \u201ctracking and reporting\u201d of emissions, whether the OWM fails to adequately \u201cpromot[e] load flexibility and demand-side resources,\u201d whether the OWM fails to \u201cpromot[e] the integration of clean energy resources,\u201d and whether joining the OWM would fail to \u201creduc[e] the costs and inefficiencies between balancing areas and between market constructs.\u201d[56]<\/a><\/sup> In short, transmission utilities must justify a request to avoid joining an OWM, but any target OWM must likewise be robust enough to satisfy the standards of Bill 72. Importantly, administrative costs will not pose a significant obstacle to OWM participation: Bill 72 states that any participating utility may be able to recover \u201cOWM subscription fees and other prudently incurred costs of participation\u201d from its ratepayers, if allowed by the CETA.[57]<\/a><\/sup> Thus, to the extent a target OWM adequately addresses the legislative concerns above, the transmission utility will be required to join that OWM.<\/p>\n <\/a><\/a> 2. Creation of the Colorado Electric Transmission Authority<\/p>\n Bill 72 also creates a new \u201cindependent special purpose authority,\u201d the Colorado Electric Transmission Authority.[58]<\/a><\/sup> The CETA is \u201cauthorized to select a qualified transmission operator to finance, plan, acquire, maintain, and operate eligible electric transmission and interconnected storage facilities.\u201d[59]<\/a><\/sup> In doing so, the CETA may issue tax-exempt revenue bonds to finance transmission projects, identify and establish intrastate corridors for transmission, exercise the power of eminent domain to acquire eligible facilities, and collect payments of fees and other charges from persons making use of the transmission facilities.<\/a>[60]<\/a><\/sup> At a high level, the CETA will \u201ccoordinate, investigate, plan, prioritize, and negotiate with entities within and outside Colorado\u201d in order to identify transmission corridors that would facilitate OWM participation, although such corridors are still subject to \u201csiting and land use approval by the local government.\u201d[61]<\/a><\/sup> Nonetheless, the CETA will be empowered with similar eminent domain authority as other governmental entities, including the power to \u201cacquir[e] any property or rights-of-way\u201d for the purposes of \u201cnecessary\u201d transmission projects (that are not owned by an electric utility or belonging to a local government).[62]<\/a><\/sup> To the extent the CETA exercises this power, any \u201c[o]wnership of eligible facilities .\u00a0.\u00a0. may not exceed the extent and duration necessary or useful to promote the public interest.\u201d[63]<\/a><\/sup><\/p>\n Importantly, Bill 72 aligns judicial review with the goals of the CETA, stating that courts shall consider \u201cthe transmission system as a whole,\u201d when deciding whether a given transmission project is in the public interest.[64]<\/a><\/sup> Ideally, this instruction will encourage courts to consider not only the individual impacts of that project but also the broader goal of expanding transmission across state borders to alleviate bottlenecks, bring down costs, and help the state reach its clean energy goals. Outside of regional transmission-planning powers, the CETA can also engage in such planning and coordination as necessary to increase Colorado\u2019s intrastate<\/em> grid reliability and resilience, to meet clean energy goals, and to evaluate alternatives to traditional transmission, such as storage and \u201cadvanced transmission technologies.\u201d[65]<\/a><\/sup><\/p>\n For better or worse, the CETA will be able to address these regional and state goals relatively unimpeded\u2014Bill 72 also contains significant regulatory independence protections for the Authority.[66]<\/a><\/sup> For example, Bill 72 states that \u201c[n]either the [CETA] nor any eligible facilities acquired by the [CETA] are subject to supervision, regulation, control, or jurisdiction of the [Colorado PUC].\u201d[67]<\/a><\/sup> Additionally, Bill 72 allows the CETA to operate under less stringent open-records and open-meetings requirements.[68]<\/a><\/sup> For example, the Authority can withhold confidential information related to costs of production and transmission, transmission service agreements, detailed power models, financing statements, and other closely held information related to a given transmission project.[69]<\/a><\/sup><\/p>\n On the other hand, the CETA applications are still subject to both PUC and local government approval\u2014though failure by either to respond within a certain statutory deadline would allow the project to proceed.[70]<\/a><\/sup> Overall, the CETA is likely to operate relatively efficiently on transmission projects as a result of fewer regulatory barriers, albeit with less oversight.[71]<\/a><\/sup> Bill 72 prioritizes efficiency and greatly empowers this new Authority, both integrating it into the existing regulatory framework and giving it streamlined operational latitude beyond even incumbent governmental entities involved in Colorado transmission planning.<\/p>\n In summary, because of Bill 72\u2019s OWM mandate, Bill 72 will significantly deepen Colorado\u2019s participation in regional wholesale markets in the West. Likewise, the CETA will oversee and ideally streamline the transmission planning process vital to the success of any OWM. Although relatively discrete and simple, the advent of these two regulatory changes will have far-reaching climate, economic, and reliability impacts on Colorado and the West.<\/p>\n <\/a><\/a> II. Motivations and Impact of Senate Bill 72 and Stakeholder Responses<\/p>\n Surely, the OWM requirement and the creation of the CETA represent significant changes to Colorado\u2019s electricity regulatory regime. But the state legislature was motivated to take this leap because of the powerful potential of Bill 72 to generate great benefits for ratepayers and utilities alike. This Section will examine these motivations and benefits, as well as Xcel\u2019s and the PUC\u2019s criticisms and ultimate support of Bill 72.<\/p>\n <\/a><\/a> A. Motivations and Impacts of Senate Bill 72<\/p>\n Key motivations behind Bill 72 include: Colorado\u2019s desire to improve its grid reliability and resilience; to save money and reduce electricity costs; and to reduce carbon emissions with transmission projects that match supply and demand across the region. This interregional coordination will \u201cunlock\u201d Colorado\u2019s grid and connect it with the rest of the West. In short, because of the OWM mandate, Bill 72 will reshape how Colorado\u2019s transmission utilities engage with wholesale energy markets in the West. At a minimum, Colorado will gain new access to renewable energy resources from the region, more transmission infrastructure focused on the regional energy market, and better reliability and resource adequacy in the state itself. This Subsection analyzes Bill 72\u2019s motivations and expected impacts related to transmission infrastructure and system reliability, resource adequacy, Colorado\u2019s climate goals, and, lastly, economic and cost saving considerations. First, this Subsection discusses regional and Colorado concerns with grid reliability and resilience and how the CETA will improve transmission planning to address these and other concerns.<\/p>\n <\/a><\/a> 1. Improving Grid Reliability and Resilience Through the CETA<\/p>\n Grid reliability (i.e., avoiding outages) and grid resilience concerns (i.e., the ability of the grid to withstand strain) require addressing the quality and amount of transmission in a service area.[72]<\/a><\/sup> The concepts are related because poor grid resilience leads to reliability issues when there is an insufficient amount <\/em>of transmission feeding a given load center. Therefore, as with the other motivations described below, the CETA\u2019s newly enshrined transmission planning authority is key to addressing these issues in the West and Colorado.[73]<\/a><\/sup> To tackle these important concerns head on, Bill 72 gives Colorado the opportunity to build more transmission infrastructure more quickly.<\/p>\n As an initial matter, the CETA is empowered to plan and coordinate transmission to address grid reliability within Colorado itself.[74]<\/a><\/sup> Although the PUC currently requires Colorado\u2019s utilities to undertake planning that addresses transmission bottlenecks (that can worsen grid strain), the CETA is the first governmental body narrowly dedicated to this task and other transmission mandates. Instead of relying only on IOUs to push for new transmission investments, the CETA is empowered to independently<\/em> identify transmission-poor areas of the state and to facilitate the development of transmission in these areas, both through state and regional coordination and through its statutory eminent domain power.<\/a>[75]<\/a><\/sup> Additionally, CETA\u2019s reduced regulatory oversight and significant power of eminent domain may speed up the approval process for transmission projects within the state\u2014although it remains to be seen how much transparency and interest-group participation the CETA will seek to facilitate or how readily the CETA would lean into its eminent domain power.[76]<\/a><\/sup> Likewise, the new standard of judicial review that includes consideration of \u201cthe transmission system as a whole, including .\u00a0.\u00a0. benefits occurring .\u00a0.\u00a0. at a regional level,\u201d widens the range of acceptable justifications for new transmission projects and perhaps lowers a previous barrier to building beneficial infrastructure.[77]<\/a><\/sup> Thus, Bill 72 and the CETA aim not only to increase transmission deployment but also to accelerate it.<\/p>\n As with many states, Colorado surely has transmission weaknesses that require investment and updating. A key example is the San Luis Valley transmission system, which serves customers in Saguache, Mineral, Rio Grande, Alamosa, Costilla, and Conejos counties.<\/a>[78]<\/a><\/sup> Because of the limited availability of lines in this system, a single <\/em>line outage could result in widespread power loss across the region.[79]<\/a><\/sup> As of 2020, efforts to evaluate transmission improvements in this area stalled before they even started: according to Xcel, the subcommittee assigned to the region concluded that \u201cthe potential costs, environmental impacts, and permitting and construction challenges .\u00a0.\u00a0. did not justify the effort required to model and analyze [the construction of new transmission lines across rugged mountainous regions].\u201d[80]<\/a><\/sup> Given the Valley\u2019s location relative to New Mexico, it is possible that this area would be cited as a transmission corridor for development by the CETA.<\/p>\n Extreme weather events also exasperate transmission weaknesses. In addition to their vast destruction of homes and natural habitats in Colorado, forest fires have damaged or destroyed transmission infrastructure itself.<\/a>[81]<\/a><\/sup> For example, in 2018, a fire near Basalt damaged three of the four electricity lines feeding Aspen, nearly de-electrifying the area.[82]<\/a><\/sup> This type of concern is particularly acute in Colorado, where a mountainous topography and frequent wildfires can easily lead to grid failure for isolated communities.[83]<\/a><\/sup> Ideally, the CETA will increase transmission redundancy on a regional level, such that a single weather event would not wipe out the only transmission access routes in the state. Threats to Colorado\u2019s grid are most acute in rural areas, but system reliability impacts all Coloradans.[84]<\/a><\/sup><\/p>\n And although discrete transmission-damaging weather events are, of course, devastating to system reliability, a 2016 study shows that the greatest outage impact on Colorado electricity customers between 1992 and 2009 came not from such weather events but instead from transmission line faults and overloads (perhaps due to poor grid resiliency).[85]<\/a><\/sup> In particular, high-demand events (i.e., hot days) put additional strain on the grid, therefore increasing the likelihood of grid failure and power outages.[86]<\/a><\/sup> As climate change fosters more intense and extended high-demand events, adequate transmission and centralized market management to optimize supply and demand across states will become even more important to avoid such outages.<\/p>\n Although the CETA\u2019s independent focus on Colorado-specific transmission issues is important, regional coordination will also be key. In the past, such planning in Colorado has occurred largely without focus on interactions with other Western states.<\/a>[87]<\/a><\/sup> Soon, Colorado utilities and the CETA will make transmission-planning decisions in the context of such a multistate marketplace.<\/p>\n At the moment, the West relies on utilities and \u201cmerchant transmission developers,\u201d who must secure both power suppliers and energy off-takers to earn revenue and take on the risk of building transmission across state borders.<\/a>[88]<\/a><\/sup> What is more, transmission-building utilities must gain approval from regulators in each state through which they pass, including approval for the costs that each state\u2019s customers will bear as a result of the project.[89]<\/a><\/sup> The CETA does not eliminate these concerns, but its consolidated authority will help to significantly streamline the approval process for new transmission and grid upgrades\u2014namely, to address grid resilience (such as updating infrastructure to increase grid capacity) and reliability (such as through wire redundancy). Unlike the current amalgamation of merchant developers and utilities pursuing interstate development, the CETA can take a top-down approach to regional transmission planning.[90]<\/a><\/sup> Hypothetically, the CETA could alleviate asymmetry of information issues between transmission developers and help reconcile different state needs and unique regulatory or geographic obstacles. And given the likelihood that non-Colorado transmission developers and utilities will want to build interstate transmission through the state, the CETA can now act as a central coordinator with the PUC and utilities across the West. In short, Bill 72 seeks to overcome both the interstate and Colorado-specific regulatory hurdles that accompany a fractured transmission planning regime.<\/p>\n On the other hand, a regional planning regime may leave cost-effective projects on the table that yield immediate benefits to Colorado.[91]<\/a><\/sup> To the extent that resources are limited, state transmission projects that only alleviate bottlenecks and improve local reliability but do not necessarily facilitate regional electricity flow might get deprioritized compared to more regionally beneficial projects, at least on the margins. As the Colorado PUC has noted, \u201ctransmission expansion [e.g., in the SPP RTO] often depends on the resolution of difficult-to-solve regional cost allocation issues and other disputes among competing interests,\u201d which presents a new barrier to transmission planning that does not currently exist in Colorado\u2019s PUC-approval process for intrastate projects.[92]<\/a><\/sup> Nonetheless, there will also be immediate benefits to the state because of centralized transmission planning.