Overview of Electric Transmission (Slide deck)

Overview of Electric Transmission (Slide deck)

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  Overview of ElectricTransmission August 2026
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  2 Electric transmission movespower over long distances, often from locations where it is generated at low cost to areas of high demand. But transmission capacity is limited— both between and within regions—and those constraints could raise costs and limit the grid’s ability to meet rising projected demand. In five sections, this document presents an overview of electric transmission, focusing on factors relevant to its buildout: ▪ What are the trends in the electric power sector? (Slides 4–11) ▪ How is the grid organized, and who builds transmission? (Slides 12–16) ▪ How is the grid overseen, and who plans and pays for upgrades? (Slides 17–21) ▪ What types of transmission lines are being built? (Slides 22–26) ▪ What other factors may affect future development of transmission? (Slides 27–30) What Is This Document About?
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  3 After years offlat demand, electricity consumption is rising, driven by growth in factors such as artificial intelligence (AI) and electrification of transportation. Studies project that transmission capacity would need to grow by 3 percent or more annually by 2050 to meet growing demand for electricity; recent buildout has been less than 1 percent per year. Most electricity is traded in wholesale markets, with most transmission built by local electric utilities. Responsibility for planning, permitting, and determining who pays for new transmission is not centralized. Rather, it is shared across multiple entities with distinct roles and incentives. Regulatory incentives favor investment in transmission by local utilities; in part because of those incentives, interregional and competitively bid projects remain a small share of total spending. Recent technological innovations and administrative actions may affect the scale and pace of new transmission capacity. Key Takeaways
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  4 Electric Transmission andTrends in the Power Sector
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  5 Data source: EnergyInformation Administration (2026a). Utility scale batteries, pumped storage, and similar technologies store and later release power and function as secondary rather than primary sources of electricity. Higher voltages are more efficient (that is, have lower line losses) when transmitting power over distance. Transformers increase the voltage from the generator for traveling through the transmission network. At the other end, transformers lower the voltage for the local distribution network to be safely used by a household. Transmission Connects Producers to Users of Power Electric power has three main components: generation, transmission, and distribution. ▪ Generation refers to the power plants that produce electricity. ▪ Transmission refers to the higher- voltage long-distance lines that connect generation with distribution, allowing electricity to flow from power plants to areas with load. ▪ Distribution refers to the local network of low-voltage lines that deliver power to electricity customers.
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  6 System Reliability Transmission allowspower to flow among broader regions—from areas with surplus production to others facing a shortfall that might stem from generator outages, extreme weather, sudden changes in demand, or other factors. Economic Transmission can reduce the overall cost of meeting electricity demand by enabling interregional trade and expanding access to lower-cost generation. Access to Generation Transmission can enable power from regions where generation is comparatively plentiful—such as hydropower in the Northwest, wind in the Midwest, or solar and geothermal in the West—to reach population and industrial centers elsewhere. Transmission Serves Several Functions for the Power System
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  7 Data sources: Jenkinset al. (2023) for 1978–1999 and 2004–2016; Congressional Budget Office, using data from Adler (2024) and FERC (2023–2026) for 2017–2024. Average Annual Growth of Transmission Capacity in Recent Decades Total U.S. transmission capacity is ~150 terawatt-miles (TW-mi). One TW-mi represents the capacity to deliver the power output of about 1,000 typical nuclear reactors over one mile. Most transmission is currently built to connect relatively nearby sources of power. Growth in annual transmission capacity has been slowing, from averaging nearly 2 percent in the 1980s and 1990s to less than 1 percent in recent years. 1.9% 1.2% 0.6% 1978–1999 2004–2016 2017–2024
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  8 Data source: CongressionalBudget Office, using data from Energy Information Administration (2026c). Electricity Demand Since 1980 After 15 years of nearly flat growth, by contrast, electricity demand as measured in terawatt-hours (TWh) has grown by about 2 percent per year over the last five years. That growth is comparable to rates last seen between the 1980s and early 2000s.
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  9 Data source: EnergyInformation Administration (2026b), “Alternative Transportation” and “High Electricity Demand” cases. Compared with EIA’s baseline case, the high electricity demand case (“EIA High Projection,” orange) reflects a significant increase in demand for AI services coupled with greater power requirements for AI servers used in data centers. EIA’s alternative transportation case (“EIA Low Projection,” blue) reflects a permanent removal of standards for greenhouse gas emissions from light- and heavy-duty vehicles. Electricity Demand Is Projected to Grow, but the Magnitude Is Uncertain The Energy Information Administration (EIA) expects that, by 2050, electricity use will grow by 25 to 50 percent of 2025 demand over a range of economic and policy scenarios. That wide range largely reflects different outcomes in the commercial and transportation sectors: ▪ High Projection. Commercial electricity use is 25 percent above EIA’s baseline for that sector, driven by high demand for data center services. ▪ Low Projection. Electricity use in transportation is 65 percent below EIA’s baseline, reflecting reduced standards for vehicle tailpipe emissions. 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2025 2030 2035 2040 2045 2050 TWh Range of U.S. Electricity Use in EIA Projections 1,970 TWh 950 TWh EIA High Projection EIA Low Projection Cumulative Increase Since 2025 2025 Demand
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  10 Data sources: CongressionalBudget Office, using data from Blanford et al. (2026), James et al. (2026), Mural et al. (2026), Smith et al. (2026), BloombergNEF (2025), Denman et al. (2025), Goldman Sachs (2025), International Energy Agency (2025), Paltsev et al. (2025), Green et al. (2024), and Vivian Lee (2024). Growth in Electricity Demand by Data Centers Is a Key Uncertainty With Wide-Ranging Estimates Estimates based on 11 sources (other than EIA) show a wide range of possible increases in electricity demand from data centers. The share of electricity use from data centers increased by about 100 TWh from 2014 to 2023, or from less than 2 percent of U.S. demand to about 4 percent. Growth in demand for data centers is expected to accelerate to between 12 and 25 percent of total load by 2035— projected increases of between roughly 400 and 1,300 TWh from use in 2023. 0 400 800 1,200 1,600 2014 2018 2022 2026 2030 2034 TWh Projected Demand for Electricity From Data Centers 2% of U.S. Demand 17% 25% 12% Average Low High 4% of U.S. Demand Share of Projected 2035 U.S. Demand
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  11 Recent studies concludethat significant growth in new transmission capacity will be necessary to meet higher levels of future electricity demand. ▪ National Transmission Planning Study (DOE 2024): 2.1–2.6 times 2020 levels by 2050 (average growth of 2.5–3.2 percent per year) However, annual transmission growth in recent years has averaged 0.6 percent. ▪ Some researchers posit that regulatory constraints are reducing the buildout of new transmission lines (Davis, Hausman, and Rose 2023; DeLosa, Pfeifenberger, and Joskow 2024; Hausman 2025). Growth of Transmission Might Lag Demand Growth
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  12 Organization of theGrid and Who Builds Transmission
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  13 Data source: GovernmentAccountability Office (2019). The contiguous United States is divided into distinct regions of electrical power: ▪ Eastern Interconnection ▪ Western Interconnection ▪ Electricity Reliability Council of Texas (ERCOT; wholly inside Texas) Those interconnects operate largely independently: ▪ Limited power flow between them. ▪ Transfer requires special conversion facilities. Each interconnection operates as a single, largely self-contained system. ▪ Transmission planning, investment, and operation occur separately within each interconnect. The North American Power Grid Consists of Three Interconnections in the Contiguous United States
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  14 Data sources: FederalEnergy Regulatory Commission (2025); Van Nostrand (2026). Most U.S. Electricity Is Traded in Wholesale Markets About 70 percent of U.S. electricity is traded in competitive wholesale markets (regional transmission organizations [RTOs] or independent system operators [ISOs], highlighted on map) ▪ Grid operators run centralized markets. ▪ Utilities purchase power from generators, sometimes located far from customers. In other regions, utilities generally own their generation and deliver electricity at regulated rates. Transmission enables trade both within and across market regions—sometimes from distant sources.
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  15 *Merchant lines maybe high-voltage direct current (HVDC) lines, in contrast with the alternating current (AC) lines used in most of the grid. Unlike AC lines, in which power flows over the path of least resistance, HVDC lines allow the owner to choose to have power flow in one direction or the other. The local electric utility ▪ Upgrades or replaces existing lines in a utility’s service territory. ▪ Proposes new lines listed mainly as being for grid reliability reasons or to connect new generators within its service territory. A private entity ▪ Can propose a new line for: • Economic reasons—for example, to transmit power from lower-cost generation in one location to another location where the cost to serve load is higher or to reduce congestion. • Public policy reasons—for example, to help a state meet a requirement to have a certain percentage of generation from zero-carbon generation. ▪ Can sometimes competitively bid to build a transmission line. ▪ In other cases, can build “merchant” lines, with rights sold to transmit power over the lines to individual generators or utilities.* Who Builds Transmission
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  16 Transmission is neededto connect new generators to the grid. Generally, the generator pays for upgrades to the transmission network to accommodate interconnection (DeLosa, Pfeifenberger, and Joskow 2024). The process of connecting generators to the grid varies among regional markets. ▪ Capacity accreditation approach (for example, PJM) • Analyzes the transmission upgrades necessary for a generator to supply firm power across all hours (energy plus capacity). • When study is complete, generator pays for the transmission upgrades and can interconnect at full capacity. ▪ Connect-and-manage approach in ERCOT • Analyzes whether enough transmission capacity is available for the generator to supply energy in at least some hours (energy only). • Generator pays only for necessary upgrades to connect; this approach is generally faster and cheaper, but generator assumes the risk of being limited to sell less power to the grid when transmission constraints are present. Transmission and the Interconnection Queue
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  17 Oversight of theGrid
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  18 The seven ISOs/RTOsare CAISO, SPP, ERCOT, MISO, ISO-NE, NYISO, and PJM. Federal: The Federal Energy Regulatory Commission (FERC) regulates the transmission and wholesale sale of electricity crossing state lines, and reviews proposed rate increases and transmission plans from grid operators. Regional: Seven RTOs/ISOs oversee high-voltage transmission operations, facilitate wholesale electricity competition across utilities, and perform long-term transmission planning. State: Public Utility Commissions (PUCs) have main responsibility for determining the need for new transmission lines and siting approval for right-of-way. Three Layers of Grid Oversight
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  19 For more onthe federal permits necessary for transmission, see “Federal Permitting Process Flowchart for a Transmission Project,” www.permittinginstitute.org/transmission-chart. States have authority over siting and permitting lines within their borders. ▪ A developer generally must show a need to the PUC. ▪ Rights of way (ROW) for the path of the transmission line must be secured. ▪ County or local jurisdictional rules may apply. ▪ Other state offices may be involved with permitting. Limited federal siting authority is available under the Federal Power Act. ▪ The Department of Energy can designate National Interest Electric Transmission Corridors (NIETCs). To date, no corridors have officially been designated, although potential corridors are under review. ▪ For projects over federal lands, federal permitting processes may apply. Interstate projects must secure ROW and permits from each state along the route; thus, interplay among regulatory entities can affect transmission buildout. ▪ For example, an RTO/ISO may propose a line that crosses state lines. ▪ Any state PUC that opposes can slow or stop the process. Siting and Permitting Is Done Predominantly by States
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  20 Transmission planning isthe process by which RTOs/ISOs, states, or both determine or evaluate which new transmission lines are needed for the grid. Most regions typically plan for individual project drivers (reliability, economic, and public policy) separately (Pfeifenberger et al. 2021). Cost–benefit analyses are typically done separately for each proposed line instead of being analyzed over a group of regional projects (Pfeifenberger et al. 2021). Planning Is Predominantly Conducted Regionally and by States
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  21 Cost allocation isthe process by which costs of a transmission line are assigned to the entities responsible for paying for it. ▪ The state PUC (or similar) reviews proposed transmission investments. ▪ If a project is deemed necessary, costs are allocated to the utility’s customers in rate hearings. Scope of cost allocation differs between regulated and deregulated states. ▪ Some states have right of first refusal (ROFR) laws; the utility must decline to build a transmission line before any other entity can build it. FERC cost causation principle: Costs are allocated proportionally to benefits. ▪ No standardized method; grid operators and states can define their own approach (Macey and Mays 2024). Paying for Transmission Combines State and Federal Elements
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  22 Types of TransmissionLines Currently Being Built
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  23 Data sources: Pfeifenbergerand Heller (2025); Congressional Budget Office, using data from Edison Electric Institute (2026). Annual Investment in Transmission by Region (1996–2024) Though growth in transmission capacity has slowed, annual investment in transmission has grown, albeit unevenly by region. Most transmission projects are local—within a utility’s service territory or an RTO/ISO region; few projects have been built across regions (Lyons and Litra 2024). Ninety percent of spending on electric transmission was driven mainly by reliability (Pfeifenberger and Heller 2025). Industry projections suggest nearly a 50 percent increase in annual investment for transmission by 2028 (Edison Electric Institute 2026).
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  24 FERC Order 1000(2011) removed the federal ROFR for incumbent utilities for building new transmission. ▪ Previously, the utility had the sole right to build transmission in its territory. ▪ The order allows competition with other developers on regional projects. A regional project is across one or more utility service territories or states. ▪ Undergoes substantial review of the potential needs and cost–benefit analyses, with costs paid by customers of some or all utilities in the RTO/ISO. ▪ Could become part of a regional planning process after corridors are identified in which transmission capacity may be needed. ▪ Must secure siting authority/permits from relevant state(s) along its route. A local or supplemental project falls within a single utility’s service territory. ▪ Undergoes limited RTO review, with costs paid by transmission owner. ▪ Generally minimal review from state PUC after RTO approval because the upgrades are deemed necessary for reliability. Types of Transmission Lines Currently Being Built: Regional Versus Local Projects
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  25 Data sources: CongressionalBudget Office, using data from FERC Monthly Energy Infrastructure Updates, www.ferc.gov/staff-reports-and-papers; NERC ES&D data for projects planned through 2034, https://tinyurl.com/NERCESD; and Pfeifenberger and Heller (2025), https://tinyurl.com/3fpr6mjn. Lower-voltage local projects built by incumbent utilities have seen most investment dollars in recent years (DeLosa, Pfeifenberger, and Joskow 2024). ▪ From 2014 to 2022 in PJM, $38.3 billion was approved for local transmission investments, compared with $6.4 billion in regional transmission. ▪ The share of overall transmission investment accounted for by local lines has increased from 30 to 80 percent in MISO and PJM over the most recent decade (Macey 2024). ▪ Over 80 percent of line miles were completed by incumbent utilities from 2011 to 2020, on average (DOE 2023); competitively bid projects were 3 percent of total transmission spending from 2013 to 2017 (Pfeifenberger et al. 2019). ▪ About two-thirds of line miles completed since 2021 have been lower voltage (230kV or below). Almost all (90 percent) historical projects and nearly 80 percent of planned projects are driven mainly by reliability. Minimal interregional transmission or transmission built across regions planned at the RTO level. Recent Trends in Types of Transmission Investment
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  26 Transmission creates “winnersand losers” (Davis, Hausman, and Rose 2023). ▪ New transmission capacity allows interconnecting lower-cost generators to meet demand or relieve congestion, thus allowing system load to be served by less-costly generation. ▪ However, existing consumers in lower-cost areas and producers in higher-cost areas are worse off. Local utility is often incentivized to build their own transmission lines (Hausman 2025). ▪ Regulated utility earns a guaranteed return on equity from its capital investments. ▪ May also oppose building of other utilities’ transmission lines near their service territory to protect the value of its existing generation assets. Local Utility Incentivized to Build in Regulatory Environment
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  27 Future Development ofTransmission
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  28 Researchers forecast increaseddemand for transmission in response to growing electricity demand and to replace aging grid infrastructure. However, several potential factors might constrain transmission investment: ▪ Planning for, siting and permitting, and determining who pays for new lines ▪ Local utility incentives in regulatory environment ▪ A wide variety of stakeholders beyond the federal government: • Local utilities (public and private) and oversight authorities • State commissions • Regional organizations (RTOs and ISOs) ▪ Open question: Would changes to any individual policy meaningfully affect private investments in transmission? Or would several policy changes be necessary? (DeLosa, Pfeifenberger, and Joskow 2024; Elmendorf, Hubbard, and Liscow 2025) Factors Affecting Future Development of Transmission
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  29 Data source: Mulvaneyet al. (2024). Grid-enhancing technologies can be added onto existing lines to increase power flows: ▪ Hardware such as dynamic line ratings, which use sensors to measure real-time weather and calculate actual line capacity—typically higher than static ratings based on worst-case conditions ▪ Nonhardware options such as topology optimization or software that can automatically reroute power flows to relieve constraints on power lines Reconductoring, or using existing ROW to replace old lines with higher-capacity lines (also referred to as advanced conductors) Minimizing need for new transmission by strategically locating storage, distributed generation, or both near constrained demand centers (for example, “behind the meter” or collocated with large users such as data centers) Technological Changes for Transmission
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  30 NIETCs are definedby the Department of Energy at least partly on the basis of their National Transmission Planning process. FERC Order 1920 ▪ Long-term regional transmission planning (at least 20 years) with consideration of • At least two other long-term scenarios, plus sensitivity analysis, and • Alternative transmission technologies—both grid-enhancing technologies and reconductoring—as an option if cost-effective. ▪ Requires regional planner to file a default, expected cost allocation method for selected regional projects. FERC Order 1977 ▪ FERC has backstop siting authority for projects proposed in federally designated transmission corridors (NIETCs). ▪ Applies in limited circumstances, such as when a state has denied an application or has not ruled on an application after the later of one year from the application filing or the designation of the NIETC. Recent Administrative Actions That May Affect Transmission
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  31 Adler, David. 2024.How CBO Uses the ReEDS Model to Analyze Policies in the Electric Power Sector, Working Paper 2024-02 (Congressional Budget Office, May), www.cbo.gov/publication/59880. Blanford, Geoff, Tom Wilson, John Bistline, and Nils Johnson. 2026. “Powering Intelligence 2026,” Electric Power Research Institute (February), https://powering-intelligence.epri.com/. BloombergNEF. 2025. “AI and the Power Grid: Where the Rubber Meets the Road” (December), https://tinyurl.com/57r8tx75. Davis, Lucas W., Catherine Hausman, and Nancy L. Rose. 2023. “Transmission Impossible? Prospects for Decarbonizing the US Grid,” Journal of Economic Perspectives, vol. 37 no. 4, (Fall), pp. 155–180, https://dx.doi.org/10.1257/jep.37.4.155. DeLosa III, Joe, Johannes P. Pfeifenberger, and Paul Joskow. 2024. “Regulation of Access, Pricing and Planning of High Voltage Transmission in the United States,” National Bureau of Economic Research, Working Paper 32254 (March), www.nber.org/papers/w32254. Denman, Aaron, Maeghan Rouch, Peter Hanbury, Padraic Brick, and Tatum Quinn. 2025. “Can the U.S. Energy Grid Keep Up With AI Data Centers?” (Bain and Company, October), https://tinyurl.com/3drhjpk6. Department of Energy. 2023. National Transmission Needs Study (October), www.energy.gov/oe/national- transmission-needs-study. Department of Energy. 2024. National Transmission Planning Study (October), www.energy.gov/gdo/national- transmission-planning-study. Edison Electric Institute. 2026. “Actual and Projected Transmission Investment” (January), https://tinyurl.com/546rs76v. References Cited
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  32 Elmendorf, Douglas W.,R. Glenn Hubbard, and Zachary Liscow. 2025. Policies to Reduce Federal Budget Deficits by Increasing Economic Growth. Working Paper 33834 (National Bureau of Economic Research, May), http://dx.doi.org/10.3386/w33834. Energy Information Administration. 2026a. Energy Explained (accessed May 2026), https://tinyurl.com/mtnrz3mv. Energy Information Administration. 2026b. Annual Energy Outlook 2026 (April), www.eia.gov/outlooks/aeo/index.php. Energy Information Administration. 2026c. Monthly Energy Review (April), www.eia.gov/totalenergy/data/monthly/index.php. Federal Energy Regulatory Commission. 2023–2026. Office of Energy Projects, Energy Infrastructure Update (Staff Reports and Papers, April 2026, April 2025, May 2024, February 2023), www.ferc.gov/staff-reports-and-papers. Federal Energy Regulatory Commission. 2025. “An Introductory Guide to Electricity Markets Regulated by the Federal Energy Regulatory Commission” (last updated April 2025), https://tinyurl.com/2rdbj6e7. Goldman Sachs. 2025. “How AI Is Transforming Data Centers and Ramping Up Power Demand” (August), https://tinyurl.com/9ufxymdd. Government Accountability Office. 2019. Critical Infrastructure Protection: Action Needed to Address Significant Cybersecurity Risks Facing the Electric Grid (August), www.gao.gov/products/gao-19-332. Green, Alastair, Humayun Tai, Jesse Noffsinger, Pankaj Sachdeva, Arjita Bhan, and Raman Sharma. 2024. “How Data Centers and the Energy Sector Can Sate AI’s Hunger for Power,” (McKinsey and Company, September), https://tinyurl.com/46ms7mfe. References Cited (continued)
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  33 Hausman, Catherine. 2025.“Power Flows: Transmission Lines, Allocative Efficiency, and Corporate Profits,” American Economic Review, vol. 155 no. 8 (August), pp. 2574–2615, https://dx.doi.org/10.1257/aer.20240276. International Energy Agency. 2025. “Energy and AI” (April), www.iea.org/reports/energy-and-ai. James, Sarah, Tony Lenoir, Ben Levitt, Dan Thompson, and Adam Wilson. 2026. “AI Infrastructure Growing Pains: Ensuring Energy Resilience Amid Grid Constraints and Public Demands” (S&P Global webinar, June), https://tinyurl.com/4wze959b. Jenkins, Jesse D., Erin N. Mayfield, Jamil Farbes, Greg Schivley, Neha Patankar, and Ryan Jones. 2023. Climate Progress and the 117th Congress: The Impacts of the Inflation Reduction Act and the Infrastructure Investment and Jobs Act (REPEAT Project, July), http://dx.doi.org/10.5281/zenodo.8087805. Lee, Vivian. 2024. “U.S. Data Center Power Outlook: Balancing Competing Power Consumption Needs” (Boston Consulting Group, June), https://tinyurl.com/2uxymp3p. Lyons, Cristin, and Greg Litra. 2024. “Transmission in the United States: What Makes Developing Electric Transmission So Hard? An Update” (ScottMadden Management Consultants), https://tinyurl.com/mrar8bdk. Macey, Joshua C. 2024. “Outsourcing Electricity Market Design,” University of Chicago Law Review, vol. 91, no. 5, (September), pp. 1243–1330, https://tinyurl.com/mv4dy8tv. Macey, Joshua, and Jacob Mays. 2024. “The Law and Economics of Transmission Planning and Cost Allocation,” Energy Law Journal, vol. 45 no. 2, (November), pp. 209–249, https://dx.doi.org/10.2139/ssrn.5018777. Mulvaney, Katie, Katie Siegner, Chaz Teplin, and Sarah Toth. 2024. “GETting Interconnected in PJM: Grid-Enhancing Technologies (GETs) Can Increase the Speed and Scale of New Entry from PJM’s Queue” (RMI, February), https://tinyurl.com/45ttspdw. References Cited (continued)
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  34 Mural, Rachel, DipeshPherwani, Chaitanya Gupta, et al. 2026. “AI, Data Centers, and the U.S. Electric Grid: A Watershed Moment” (Harvard Kennedy School, February), https://tinyurl.com/ymwesmkb. Paltsev, Sergey, C. Adam Schossler, Etienne Berthet, et al. 2025. “2025 Global Change Outlook” (Massachusetts Institute of Technology), https://tinyurl.com/yc38e7mw. Pfeifenberger, Johannes, and Peter Heller. 2025. “Interregional Transmission and Benefits From Improved Planning” (Brattle Group, December), https://tinyurl.com/3fpr6mjn. Pfeifenberger, Johannes, Judy Chang, Akarsh Sheilendranath, J. Michael Hagerty, Simon Levin, and Wren Jiang. 2019. Cost Savings Offered by Competition in Electric Transmission (Brattle Group, April), https://tinyurl.com/yajnjjfh. Pfeifenberger, Johannes, Kasparas Spokas, J. Michael Hagerty, et al. 2021. Transmission Planning for the 21st Century: Proven Practices That Increase Value and Reduce Costs (Brattle Group and Grid Strategies, October), https://tinyurl.com/3zjz7a8k. Smith, Sarah J., Alex Hubbard, Alex Newkirk, et al. 2026. “United States Data Center Energy Usage Report: 2025 Update” (Lawrence Berkeley National Laboratory, June), https://doi.org/10.71468/P1RP4F. Van Nostrand, James. 2026. “High Natural Gas, High Electricity Prices” (Kleinman Center, “Implications of Rising Energy Costs: A Kleinman Center and Perry World House Q&A”, May), https://tinyurl.com/e7pksbmv. References Cited (continued)
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  35 In keeping withthe Congressional Budget Office’s mandate to provide objective, impartial analysis, the document makes no recommendations. David Adler and Ron Gecan prepared the document, with guidance from Nicholas Chase and Joseph Kile. Ann Futrell, Aaron Krupkin, Alaina Rhee, Molly Sherlock, and Heidi Williams (a CBO contractor) offered comments. Catherine Hausman of the University of Michigan commented on an earlier draft. The assistance of external reviewers implies no responsibility for the final product; that responsibility rests solely with CBO. Jeffrey Kling reviewed the document, and Gabe Waggoner edited it. The document is available at www.cbo.gov/publication/62705. CBO seeks feedback to make its work as useful as possible. Please send comments to communications@cbo.gov. About This Document