The generation resource mix is changing rapidly. Due to a myriad of factors—including improving economics, customer and corporate demand for clean energy, public utility commitments and integrated resource plans, as well as federal, state, and local public policies—renewable resources in particular are coming online at an unprecedented rate. As a result, the transmission needs of the electricity grid of the future are going to look very different than those of the electricity grid of the past.
We are concerned that the current approach to transmission planning and cost allocation cannot meet those future transmission needs in a manner that is just and reasonable and not unduly discriminatory or preferential. In particular, we believe that the status quo approach to planning and allocating the costs of transmission facilities may lead to an inefficient, piecemeal expansion of the transmission grid that would ultimately be far more expensive for customers than a more forward-looking, holistic approach that proactively plans for the transmission needs of the changing resource mix. A myopic transmission development process that leaves customers paying more than necessary to meet their transmission needs is not just and reasonable.
In that regard, we are pleased to see the Commission taking a consensus first step toward updating its rules and regulations to ensure that we are meeting the nation’s evolving transmission needs in a cost-effective and efficient fashion. Today’s action complements our recently established joint federal-state task force with the National Association of Regulatory Utility Commissioners, which we expect to produce a robust dialogue on many of the issues addressed herein. In our view, this advance notice of proposed rulemaking (ANOPR) is just the first step. Ensuring that transmission rates remain just and reasonable will require further action, including reforms to interregional transmission planning and cost allocation, as well as other reforms to our regional transmission planning and cost allocation and generator interconnection processes beyond those contemplated herein. Nevertheless, we believe that today’s unanimous Commission action represents a solid foundation for an expeditious inquiry into how we can regulate to achieve the transmission needs of our changing electricity system in a manner consistent with our statutory obligations under the Federal Power Act.
The generation mix is shifting rapidly from large resources located close to population centers toward renewable resources, often combined with onsite storage, that tend to be located where their fuel source is best—i.e., where the wind blows hardest or the sun shines brightest. According to the National Renewable Energy Laboratory (NREL), total renewable generation capacity nearly doubled from 2009 to 2018, increasing from 11.7% of total generation capacity to 20.5%. And that is just the beginning: of the roughly 750 GW of generation in interconnection queues around the country, nearly 700 GW are renewable resources, providing every reason to believe that the dramatic shift toward renewable generation will only accelerate in the years ahead.
That shift is the result of many factors. First and foremost, the cost of renewable resources is plummeting. For example, in its annual report on the levelized cost of energy, Lazard found that between 2009 to 2020, the levelized cost of energy from unsubsidized wind generation and unsubsidized utility-scale solar generation decreased by 71% and 90%, respectively—enough to make utility-scale solar and wind generation cost-competitive with central station fossil generation sources in many parts of the country. Moreover, customers—both residential and commercial—are increasingly demanding clean energy, particularly energy from renewable resources—which is itself causing utilities and independent power producers to attempt to send large quantities of renewable energy onto the grid. In addition, dozens of the biggest utilities in the country have established their own decarbonization goals, the achievement of which will require their own significant investment in renewable generation.
Finally, federal, state, and local policymakers have adopted a range of public policies that are driving the changing resource mix. For example, 30 states and the District of Columbia have adopted renewable portfolio standards, with those standards contributing to roughly 50% of the total growth in renewable generation over the last two decades. In addition, several states have doubled down on the clean energy transition by enacting measures that require that most or all of their electricity come from zero emissions resources. All told, “states and utilities that have committed to transitioning to 100 percent clean power serve nearly 83 million households and businesses, representing around 50 percent of all U.S. electricity demand in 2019.”
Dramatic changes in the resource mix inevitably come with similarly dramatic changes in transmission needs. As noted, the increasingly cost-competitive renewable resources that customers and public policies demand tend to be developed farther away from customers where their fuel sources are strong and development costs are low rather than in close proximity to their ultimate customers. As a result, the future resource mix will likely present new transmission needs, different from those of the large resources located close to population centers that have dominated electricity generation in the past. Meeting those transmission needs will likely require both the infrastructure necessary to interconnect new resources to the transmission system efficiently and the infrastructure necessary to reliably move the electricity produced by those resources to where it is needed. This could make it considerably more expensive than necessary to bring in the low-cost generation demanded by customers and meet federal, state, and local public policies.
This Commission cannot sit idly by. Our role is to ensure just and reasonable rates and support reliability in light of changes in the market, not to pretend those changes are not happening. We are concerned that, in light of evolving transmission needs, the current regional transmission planning and cost allocation and generator interconnection processes may no longer ensure just and reasonable rates for transmission service. In particular, we are concerned that existing regional transmission planning processes may be siloed, fragmented, and not sufficiently forward-looking, such that transmission facilities are being developed through a piecemeal approach that is unlikely to produce the type of transmission solutions that could more efficiently and cost-effectively meet the needs of the changing resource mix. Regional transmission planning processes generally do little to proactively plan for the resource mix of the future, including both commercially established resources, such as onshore wind and solar, as well as emerging ones, such as offshore wind. We are also concerned that current regional transmission planning processes are not sufficiently integrated with the generator interconnection processes, and are overwhelmingly focused on relatively near-term transmission needs, and that attempting to meet the needs of the changing resource mix through such a short-term lens will lead to inefficient transmission investments. As a result, under the status quo, customers could end up paying far more to meet their transmission needs than they would under a more forward-looking approach that identifies the more efficient or cost-effective investments in light of the changing resource mix.
Relatedly, we are also concerned that the current approach to transmission planning and cost allocation is failing to adequately identify the benefits and allocate the costs of new transmission infrastructure. Although the regional transmission planning process considers transmission needs driven by reliability, economics, and Public Policy Requirements, those transmission needs are often viewed in isolation from one another and the cost allocation methods for projects selected to meet those needs are similarly siloed. As a result, the status quo may be disproportionately producing transmission facilities that address a narrow set of needs, providing comparatively modest benefits, but at a still-substantial total cost instead of developing the type of transmission infrastructure that could provide the most significant benefits for customers. In the same vein, we are also concerned that many customers who share in the diverse array of benefits that transmission infrastructure can offer may not be paying their fair share, as required by the cost causation principle.
In addition, we are concerned that, largely due to the potential shortcomings with the current regional transmission planning and cost allocation processes, transmission infrastructure is increasingly being developed through the generator interconnection process. That means that infrastructure with potentially significant benefits for a broad range of entities may be developed through a process that focuses exclusively on the needs of a comparatively small number of interconnection customers—a dynamic that is almost sure to result in comparatively inefficient investment decisions. The participant funding approach to financing interconnection-related network upgrades will often mean that the interconnection customer(s) alone must pay for all—or the vast majority—of the costs of that transmission infrastructure, even where it provides significant benefits to other entities. That, in turn, may cause those interconnection customers to withdraw projects from the queue, causing considerable uncertainty and delay, and may mean that net beneficial transmission infrastructure is never developed due to a misalignment in how that infrastructure would be paid for.
Finally, we are also concerned that the Commission’s current approach to overseeing transmission investment may not adequately protect consumers. While transmission infrastructure can provide a broad spectrum of benefits, it is itself a significant investment that represents a major component of customers’ electric bills. The Commission must vigorously oversee the rules governing how transmission projects are planned and paid for if we are to satisfy our responsibility to protect customers from excessive rates and charges. The potential bases for invigorating our oversight of transmission spending contemplated in today’s order have the potential to go a long way toward ensuring that we fulfill that function.
Today’s action plants the seeds for addressing the concerns outlined above. A forward-looking, holistic approach to transmission planning has the potential to identify the more efficient or cost-effective solutions for meeting the transmission needs of the changing resource mix, including those resources that are not yet under development. Such an approach would allow transmission planners to proactively identify the areas of the transmission grid that will have significant transmission needs and select the more efficient or cost-effective solution to meet those needs, including needs driven by resources that are not yet in operation or even under development. Doing so has the potential to address the transmission needs of the future generation mix while costing customers considerably less than they would pay to meet those same needs under the status quo. That, in our view, is what is necessary to ensure that the rates for transmission service remain just and reasonable as the resource mix changes.
We anticipate that this effort will be the Commission’s principal focus in the months to come. In addition to reviewing the record assembled in response to today’s order, we intend to explore technical conferences and other avenues for augmenting that record—including through the joint federal-state task force—before proceeding to reform our rules and regulations. We recognize that the issues addressed herein are highly technical, complex problems that do not lend themselves to easy solutions. That being said, we also recognize the urgent need to address the transmission needs of the changing resource mix and appreciate that we do not have the luxury of sitting back and debating these issues ad nauseum.
The electricity sector is at a pivotal moment. With the clean energy transition gaining steam, we can either continue with the status quo, trying to meet the transmission needs of the future by building out the grid in a myopic, piecemeal fashion, or we can start holistically and proactively planning for those future transmission needs. We believe that today’s advance notice of proposed rulemaking represents an important and essential first step in the right direction and toward the type of transmission planning and cost allocation paradigm that is necessary to protect customers, support reliability, and ensure just and reasonable rates.
 See, e.g., Joseph Rand et al., Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection as of the End of 2020, Lawrence Berkeley National Laboratory, May 2021, https://eta- publications.lbl.gov/sites/default/files/ queued_up_may_2021.pdf.; Electric Power Monthly, Table 6.1 Electric Generating Summer Capacity Changes (MW), U.S. Energy Information Administration, (Mar. 2021 to Apr. 2021), https://www.eia.gov/electricity/monthly/ epm_table_grapher.php?t=table_6_01.
 Joint Federal-State Task Force on Electric Transmission, 175 FERC ¶ 61,224 (2021).
 2018 Renewable Energy Data Book at 26, NREL, https://www.nrel.gov/docs/ fy20osti/75284.pdf. Wind and solar resources, in particular, have grown at a disproportionate rate, with solar generation capacity increasing roughly 5,000% from 1,054 MW to 51,899 MW nationwide, and wind generation capacity more than tripling from 31,155 MW to 96,442 MW.
 See Joseph Rand, Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection as of the End of 2020, Lawrence Berkeley National Laboratory, May 2021, https://eta-publications.lbl.gov/sites/default/files/ queued_up_may_2021.pdf. Equally important, this shift is taking place across the country, not just in a few areas. For example, as of the issuance of this ANOPR, in Midcontinent Independent System Operator, Inc. (MISO), solar and wind projects comprise 80% of all active projects in the current interconnection queue, or about 73 GW of total capacity. MISO, Generator Interconnection Queue – Active Projects Map, https://giqueue.misoenergy.org/PublicGiQueueMap/ index.html. Similarly, in PJM Interconnection, L.L.C. (PJM), solar and wind projects with a total capacity of 62 GW comprise 79% of all active projects in the current interconnection queue as of the issuance of this ANOPR. PJM, New Services Queue, https://www.pjm.com/planning/services-requests/interconnection-queues.aspx. In California Independent System Operator Corporation (CAISO), renewable and storage capacity of 23 GW comprise 78% of all active projects in the current interconnection queue as of the issuance of this ANOPR. CAISO, Generator Interconnection Queue, https://www.caiso.com/Documents/ISOGeneratorInterconnectionQueueExcel.xls.
 See, e.g., Lazard’s Levelized Cost of Energy Analysis — Version 14.0, at 9 (Oct. 19, 2020), https://www.lazard.com/perspective/levelized-cost-of-energy-and-levelized-cost-of-storage-2020/#:~:text=Lazard’s%20latest%20annual%20Levelized% 20Cost,build%20basis%2C%20continue%20to%20maintain; Ryan Wiser et al., Expert elicitation survey predicts 37% to 49% declines in wind energy costs by 2050, Lawrence Berkeley National Laboratory (Apr. 2021), https://eta-publications.lbl.gov/ sites/default/files/wind_lcoe_elicitation_ne_pre-print_april2021.pdf (finding that the decrease in levelized cost of energy for wind power from 2015-2020 outpaced the decrease predicted by experts, and that experts continue to predict significant declines in levelized cost of energy).
 See Lazard’s Levelized Cost of Energy Analysis — Version 14.0, at 3, 7 (Oct. 19, 2020), https://www.lazard.com/perspective/levelized-cost-of-energy-and-levelized-cost-of-storage-2020/#:~:text=Lazard’s%20latest%20annual%20Levelized% 20Cost,build%20basis%2C%20continue%20to%20maintain.
 See, e.g., Deloitte Resources 2020 Study at 22, https://www2.deloitte.com/ content/dam/insights/us/articles/6655_Resources-study-2020/DI_Resources-study-2020.pdf (showing that U.S. corporate renewable generation purchase power agreements increased from 0.3 GW in 2009 to 13.6 GW in 2019); Kevin O’Rourke & Charles Harper, Corporate Renewable Procurement and Transmission Planning: Communicating Demand to RTOs Necessary to Secure Future Procurement Options, A Renewable America (October 2018), https://acore.org/wp-content/uploads/2020/04/Corporates-Renewable-Procurement-and-Transmission-Report.pdf (indicating that a group of corporations, forming the Renewable Energy Buyers Alliance, has set a goal to purchase 60 GW of new renewable energy capacity in the U.S. by 2025); Stanley Porter et al., Utility Decarbonization Strategies, Renew, Reshape, and Refuel to Zero, Deloitte Insights (Sept. 2021), https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/utility-decarbonization-strategies.html (indicating that 43 of 55 utilities surveyed have emissions reductions targets and 22 have net-zero or carbon-free electricity goals); Esther Whieldon, Path to net zero: 70% of biggest US utilities have deep decarbonization targets, S&P Global Market Intelligence (Dec. 9, 2020) at 3-6, https://www.spglobal.com/marketintelligence/en/news-insights/latest-news- headlines/path-to-net-zero-70-of-biggest-us-utilities-have-deep-decarbonization-targets-61622651 (indicating that review of utilities’ climate goals decarbonization plans, as of December 2020, shows that 70% of the 30 largest utilities have net-zero carbon targets or are moving to comply with similarly aggressive state mandates); see also Rich Glick and Matthew Christiansen, FERC and Climate Change, 40 Energy L.J. 1, 7-12 (2019) (“The growth of renewable resources is also a function of consumers’ desire for clean energy. Customers—including residential, commercial, and even industrial consumers—are increasingly demanding that their energy come from renewable or zero-emissions sources”).
 See, e.g., Corporate Renewable Procurement and Transmission Planning: Communicating Demand to RTOs Necessary to Secure Future Procurement Options, A Renewable America, October 2018, https://acore.org/wp-content/uploads/2020/04/Corporates-Renewable-Procurement-and-Transmission-Report.pdf; Esther Whieldon, Path to net zero: 70% of biggest US utilities have deep decarbonization targets, S&P Global Market Intelligence, Dec. 9, 2020, at 3-6, https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/path-to-net-zero-70-of-biggest-us-utilities-have-deep-decarbonization-targets-61622651.
 Nat’l Conference of State Legislatures, State Renewable Portfolio Standards and Goals (Nov. 7, 2021), https://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx#:~:text=Thirty%20states%2C%20Washington%2C%20D.C.%2C,have%20set%20renewable%20energy%20goals. Renewable portfolio standards are policies that are designed to increase the amount of renewable energy sources used for electricity generation.
 See, e.g., Berkeley Lab, U.S. Renewables Portfolio Standards: 2019 Annual Status Update (Aug. 2019), https://emp.lbl.gov/publications/us-renewables-portfolio-standards-2.
 Carbon Pricing in Organized Wholesale Elec. Markets, 175 FERC ¶ 61,036, at P 2 (2021) (“Thirteen states—California, Hawaii, Maine, Maryland, Massachusetts, Nevada, New Jersey, New Mexico, New York, Oregon, Vermont, Virginia, and Washington—and the District of Columbia have adopted clean energy or renewable portfolio standards of 50% or greater.”). In addition, “a number of states—including Colorado, Connecticut, Nevada, Rhode Island, and Wisconsin—have established 100% clean electricity goals or targets by executive order or other non-binding commitment.” See id. At the local level, cities and counties are also accelerating clean energy commitments. Kelly Trumbull et al., Progress Toward 100% Clean Energy in Cities and States Across the U.S., University of California - Los Angeles Luskin Center for Innovation (November 2019) at 10, https://innovation.luskin.ucla.edu/wp-content/uploads/2019/11/100-Clean-Energy-Progress-Report-UCLA-2.pdf (finding over 200 cities and counties across 37 U.S. states have 100 percent clean energy commitments).
 National Resources Defense Council (NRDC), NRDC’s 8th Annual Energy Report: Slow and Steady Will Not Win the Climate Race (Dec. 2, 2020), https://www.nrdc.org/resources/nrdcs-8th-annual-energy-report-slow-and-steady-will-not-win-race?nrdcpreviewlink=rmmB6NM6zpiOTruhuObZJdH92bCOvmZTY1hx72xCSzQ#renewables.
 16 U.S.C. § 824e.
 See generally Eric Larson et al., Net-Zero America: Potential Pathways, Infrastructure, and Impact (2020), Princeton_NZA_Interim_Report_15_Dec_2020_FINAL.pdf (discussing different pathways for meeting decarbonization goals, including differing approaches to transmission investment).
 See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 136 FERC ¶ 61,051, at P 11 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).
 Cf. BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264, 268-269 (D.C. Cir. 2014) (“[T]he cost causation principle itself manifests a kind of equity. This is most obvious when we frame the principle (as we and the Commission often do) as a matter of making sure that burden is matched with benefit.” (citing Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) and Se. Michigan Gas Co. v. FERC, 133 F.3d 34, 41 (D.C. Cir. 1998))).
 Cf., e.g., California ex rel. Lockyer v. FERC, 383 F.3d 1006, 1017 (9th Cir. 2004) (rejecting “an interpretation [that] comports neither with the statutory text nor with the Act’s ‘primary purpose’ of protecting consumers”); City of Chicago v. FPC, 458 F.2d 731, 751 (D.C. Cir. 1971) (“[T]he primary purpose of the Natural Gas Act is to protect consumers.” (citing, inter alia, City of Detroit v. FPC, 230 F.2d 810, 815 (D.C. Cir. 1955)).
 See supra n.2.