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When is Renewable not Renewable? The Constitutionality of State Laws Denying New Large Canadian Hydroelectric Projects Treatment as Renewable Resources

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Harvey L. Reiter*

I.         Introduction

Over the past fifteen years, many states—twenty-nine at last count—have adopted renewable portfolio standards (RPS) as a means both to reduce their dependence on imported fossil fuels and to combat climate change.[1] To comply with these standards, electric utilities must demonstrate that a significant minimum percentage of their supply portfolios will consist of renewable resources by the various target dates specified in state law.[2] Most states affirmatively describe what counts as renewable resources—wind, geothermal, and solar energy are commonly referenced in RPS legislation.[3] But some state RPS laws also contain negative provisions, excluding from eligibility what otherwise would surely be considered renewable resources.[4] Hydroelectric projects are quintessential examples of renewable energy sources.[5] The fuel source—water—replenishes itself. It rains; the rain evaporates and condenses; and the cycle starts all over again. Under these laws, however, only new small-scale hydroelectric projects count as renewable resources. Large-scale hydroelectric projects, both existing and new, do not.[6]

Laws of this type amount to hidden barriers to power imports from Canada, the only source of electricity from new large-scale hydroelectric facilities. This article explains why the restrictions are unconstitutional under the Commerce Clause and bad for consumers and the environment, and why other states should follow the lead of Vermont and Wisconsin and modify their statutes to permit power from large hydroelectric projects to be treated as a renewable resource under their RPS laws.

II.         The “Dormant” Commerce Clause and State Regulation of Foreign Commerce

The Commerce Clause gives the federal government authority to regulate interstate and foreign commerce.[7] The courts have found this power to be exclusive and, by negative implication, to bar states from unduly burdening or discriminating against interstate and foreign commerce.[8] Perhaps because the temptation of legislators to protect local businesses is so strong, cases under which the federal courts have struck down state legislation invoking this implicit, or “dormant,” Commerce Clause restriction are “legion.”[9]

Although most of these cases have involved legislation that disadvantages out-of-state interests, the Clause also serves to prevent states from erecting barriers to foreign commerce. “Power to regulate foreign commerce,” after all, “is given in the same words, and in the same breath, as it were, with that over the commerce of the States and with the Indian tribes.”[10] And, just as the power to regulate interstate commerce resides exclusively with the federal government, the power to regulate commerce with other nations is also solely federal.[11]

The impact of the Commerce Clause on state laws affecting foreign commerce, in fact, is somewhat broader than in the case of state laws affecting interstate commerce. “Like the Import-Export Clause, the Foreign Commerce Clause recognizes that discriminatory treatment of foreign commerce may create problems, such as the potential for international retaliation, that concern the Nation as a whole.”[12] This means, of course, that a state cannot protect in-state interests by granting them preferential treatment over foreign competitors.[13] But it also means that “a State’s preference for domestic commerce over foreign commerce is inconsistent with the Commerce Clause even if the State’s own economy is not a direct beneficiary of the discrimination.”[14]

III.         Large-Scale Hydro Restrictions as De Facto Barriers to Foreign Competition

Numerous articles in recent years have discussed how various state RPS laws discriminate against interstate commerce in violation of the Commerce Clause.[15] Many of these same state laws include provisions declaring that large-scale hydroelectric facilities, both new and existing, are not to be considered renewable resources.[16] None of the articles discussing in-state preferences, however, address whether the large hydro exclusions also operate as in-state preferences. But, as discussed below, the large-scale hydro exclusions are de facto restrictions on the import of Canadian hydropower since the only new sources of large-scale hydroelectric power are located in Canada. The constitutional and economic significance of that fact is the subject of this Article.

Had states that have chosen to exclude large scale hydroelectric projects from treatment as renewable resources confined the exclusion to existing facilities, no constitutional issue would have been presented. Where states are already hydro-rich, restrictions on counting existing large-scale hydroelectric facilities as renewable resources would serve the obvious purpose of promoting the development of new renewable resources.[17] This may or may not be good policy,[18] but it is not fashioned to exclude out-of-state or foreign competitors. Consider Washington, for example. It accounts for more than a quarter of all the hydroelectric power production in the United States, and, not surprisingly, well over half of the electricity its residents and businesses use comes from hydroelectric facilities.[19] If existing hydroelectric facilities counted toward a renewable portfolio goal of, say, thirty percent, there would be no impetus to develop any new renewable energy sources. And, since the states that have chosen to adopt these restrictions already have their own existing hydroelectric facilities,[20] the purpose of the exclusion would be neutral from a Commerce Clause perspective. This is so, even though the statutory distinction is fictitious; existing hydroelectric facilities produce energy from water, an indisputably renewable energy source.[21]

But the picture is completely different where the exclusion extends, as it does in several states, to new large-scale hydroelectric projects.[22] Although the statutes in question do not single out Canadian energy suppliers, a restriction can be discriminatory under the Commerce Clause even if it is not express.[23] The viable sites for new large-scale hydroelectric production are located in British Columbia, Manitoba and Québec,[24] the three Canadian provinces with the largest hydroelectric output.[25] It is of course true that a state law does not discriminate against out-of-state (or foreign) commerce simply because it adversely affects out-of-state or foreign entities.[26] But when a state excludes new large-scale hydroelectric facilities, even for ostensibly environmental reasons, its only targets are foreign producers. There are no sites left in the United States where large-scale hydro facilities can be developed.[27] The de facto effect of the restrictions, then, is to limit competition from Canadian entities to supply renewable energy. This should be enough of a reason to strike down the restrictions on Commerce Clause grounds as state interference with federal regulation of foreign trade.[28]

Were proof of a discriminatory or protectionist motive needed, however, there seems ample evidence to support that conclusion as well. Renewable energy advocates in New England, for example, have successfully argued that defining large hydroelectric facilities as renewable resources “would slow down the development of renewable energy projects in the region.”[29] This, in fact, was official government policy in Vermont for over a quarter century. “Vermont policy-makers reached a consensus that if large hydropower were deemed renewable, it would hinder the development of smaller renewable energy projects.”[30] And New Hampshire’s protectionist intent is quite explicit. The text of its RPS states as its “purpose” that “[r]enewable energy generation technologies can provide fuel diversity to the state and New England generation supply through use of local renewable fuels and resources that serve to displace and thereby lower regional dependence on fossil fuels.”[31]

To be sure, there are unquestionable environmental concerns associated with the construction and operation of large-scale hydroelectric facilities. “Damming rivers,” notes former Vermont Public Service Board Member David Coen (an advocate for treating large hydroelectric projects as renewable resources), “forever alters a region’s geologic landscape, and a hydroelectricity facility’s turbines often kill the fish that get caught in the plant.”[32] And, he adds “roughly 600 dams have been removed in the last 50 years” because of “safety concerns and concerns over their long-term impact on the environment and recreation.”[33]

It is highly doubtful, however, that environmental concerns about large-scale hydroelectric projects in Canada could justify denying their eligibility as renewable resources. For one thing, a good environmental motive will not save discriminatory legislation. “Even if environmental preservation were the central purpose” of a state law or regulation, it “would not be sufficient to uphold a discriminatory regulation.”[34]

In any event, restrictions like exclusions from RPS eligibility are economic, not environmental. Canadian hydropower producers are not banned from exporting; their products are simply not credited toward meeting the buyer’s renewable portfolio obligations.[35] Indeed Canadian suppliers continue to sell large amounts of hydroelectric power to U.S. buyers.[36] Several New England states have proposed legislation to ease restrictions on the eligibility of large hydro facilities to satisfy renewable energy targets.[37] But, the environmental groups that have opposed these initiatives have, no doubt unintentionally, articulated their concerns in economic, not environmental terms.

When, for example, New Hampshire was considering legislation to allow large hydro to qualify as a renewable resource, the Conservation Law Foundation described the legislation as simply a way to allow Hydro-Québec to take business away from homegrown renewables. As one reporter recounted the statement of the Foundation’s director:

Tom Irwin, VP and Director of the Conservation Law Foundation, New Hampshire, writes in his blog that HB 302 is “clearly intended to tilt the playing field in favor of the Northern Pass.” He said that “HB 302 will greatly undermine one of the core purposes of New Hampshire’s RPS law: the stimulation of investment in renewable energy technologies in New England and, in particular, in New Hampshire.”[38]

Mr. Irwin’s objections, in other words, were not that removing the limitations would damage the environment, but that they would force New Hampshire’s mom and pop renewable energy producers to compete with the Hydro-Québec behemoth. That may articulate a populist theme, but it is not an environmental one.

IV.         Conclusion

As the courts have construed it, the core purpose of the interstate commerce provisions of the Commerce Clause was to prevent states from erecting protectionist barriers to interstate trade.[39]  By contrast, as University of Chicago law professor Richard Epstein put it, “there was clear, if regrettable, evidence that protectionism against foreign competition was one reason why Congress was given (and given first) power over foreign commerce” in the very same provision of the Constitution.[40]  In other words, if anyone was going to discriminate against foreign competition, it would be the federal government, not the states.

Happily, the conflicting motives behind the inclusion of these two aspects of the Commerce Clause do not produce conflicting Constitutional outcomes. Even accepting an environmental impetus for restrictions on the treatment of new large hydro facilities under state RPS laws, under the Commerce Clause the judgment whether to limit foreign imports based on environmental (or any other) considerations would reside exclusively with the federal government, not the states. And while the federal government’s silence would not create space for state-imposed restrictions on foreign trade, here the federal government has spoken loudly against trade restrictions through ratification of both the North American Free Trade Agreement (NAFTA) and its companion treaty, the North American Agreement on Environmental Cooperation (NAAEC). The latter obligates each of the signatory states—Canada, Mexico, and the United States—to adhere to responsible environmental policies.[41] So, not only are states barred from erecting their own barriers to foreign competition, but the federal government has made a policy choice that it should embrace competition from Canada and Mexico as well.

This, in the author’s view, is a good outcome for consumers and for the environment. There are certainly environmental concerns associated with the development of large-scale hydroelectric projects. But, no renewable resource is without its warts.[42] Just as hydroelectric projects can alter an ecosystem and damage aquatic life, so too can wind farms and large solar arrays pose risks to birds and other wildlife.[43] And, somewhat counterintuitively, large solar installations, if not dry cooled, can also put stress on critical water resources.[44] Constitutional considerations aside, the solution is to mitigate environmental effects, not to erect economic barriers to the use of carbon-free technology.

The question from the consumers’ perspective is why, if the goal is to reduce carbon emissions, should they be forced to pay for less efficient and more costly solar or wind-based power when equally carbon-free hydroelectric power is available for less? Propping up local businesses or protecting local jobs by erecting trade barriers is simply bad economics. “[W]hile protectionism is sold as job saving, it probably really amounts to job swapping. It protects jobs in some industries only by destroying jobs in others.”[45]

Protectionist economic legislation targeting efficient sources of renewable energy may cause the environment to suffer as well. With scarce dollars to go around, subsidizing inefficient or comparatively less efficient home grown renewable resources leaves fewer consumer resources to pay for other climate-friendly options, like energy efficient devices or conservation technologies.[46]

Vermont, no environmental slouch among the states, made the choice a few years ago to remove its longstanding restriction on the treatment of new large hydroelectric facilities as renewable resources.[47] Wisconsin followed suit about a year later.[48] One can hope that, in the interests of consumer protection—or maybe simply to forestall legal challenges by disadvantaged foreign competitors and their would-be customers—other states will follow their lead.

 

Preferred citation: Harvey L. Reiter, When is Renewable not Renewable? The Constitutionality of State Laws Denying New Large Canadian Hydroelectric Projects Treatment as Renewable Resources, 5 Harv. Bus. L. Rev. Online 76 (2015), https://www.hblr.org//?p=3993.

* Partner, Stinson Leonard Street, LLP, Washington, D.C. J.D., Boston University School of Law, B.A., Michigan State University. Executive Articles Editor, Energy Law Journal (2007–present), Adjunct Professor, Vermont Law School (2010–11). The author extends special thanks to Delia Patterson, General Counsel of the American Public Power Association, for her valuable comments and insights.

[1] The latest Environmental Protection Agency figures say that, as of March 2013, twenty-nine states and the District of Columbia have adopted binding renewable portfolio standards; eight more states have adopted non-binding renewable portfolio goals. Renewable Portfolio Standards, Envtl. Protection Agency, http://www.epa.gov/agstar/tools/funding/renewable.html (last visited Mar. 6, 2015).

[2] Id.; see also Renewable Portfolio Standard Policies, U.S. Dep’t. of Energy, http://www.dsireusa.org/documents/summarymaps/RPS_map.pdf (last visited Mar. 6, 2015) (displaying map listing renewable portfolio target dates by state).

[3] See Renewable Portfolio Standards, Envtl. Protection Agency, http://www.epa.gov/agstar/tools/funding/renewable.html (last visited Mar. 6, 2015). The Department of Energy maintains a comprehensive list of renewable resource programs and the types of resources that qualify as renewable in the Database of State Incentives for Renewables & Efficiency (DSIRE). See Database of State Incentives for Renewables & Efficiency, U.S. Dep’t. of Energy, http://www.dsireusa.org/ (last visited Mar. 19, 2015).

[4] See, e.g., KSE Focus, States Debate Large-Scale Hydro Power and Renewable Portfolio Standards, Congress.org (Aug. 7, 2013), http://congress.org/2013/08/07/state-debate-large-scale-hydro–power-and-renewable-portfolio-standards/.

[5] The American Heritage New Dictionary of Cultural Literacy defines a renewable resource as “any resource, such as wood or solar energy, that can or will be replenished over time.” The New Dictionary of Cultural Literacy: What Every American Needs to Know 519 (James Trefil et al. eds., 3d ed. 2005). Energy Information Administration’s “Energy Kids” website similarly defines renewable energy sources as those that “can be replenished,” and identifies biomass, hydropower, geothermal, wind and solar as the five most common forms of renewable energy. Energy Sources—Renewable, Energy Kids, U.S. Energy Info. Admin., http://www.eia.gov/kids/energy.cfm?page=renewable_home-basics (last visited Mar. 6, 2015).

[6] See Val Stori, Environmental Rules for Hydropower in State Renewable Portfolio Standards 4, CleanEnergy States Alliance (April 2013), http://www.cesa.org/assets/2013-Files/RPS/Environmental-Rules-for-Hydropower-in-State-RPS-April-2013-final-v2.pdf (“the majority of states allowing existing hydropower facilities to qualify for the RPS restrict eligibility to ‘small’ hydro facilities”); David C. Coen & Robert J. Thormeyer, Should Large Hydroelectric Plants be Treated as Renewable Resources?, 32 Energy L.J. 541, 543–44 (2011).

[7] U.S. Const. art. I, § 8, cl. 3. The Commerce Clause grants Congress the “power . . . [t]o regulate Commerce with foreign Nations, and among the several States, and with the Indian Tribes.” Id.

[8] Or. Waste Sys., Inc. v. Dep’t of Envtl. Quality of State of Or., 511 U.S. 93, 98 (1994) (citing Wyoming v. Oklahoma, 502 U.S. 437, 454 (1992)).

[9] See West Lynn Creamery, Inc. v. Healy, 512 U.S. 186, 194 (1994).

[10] Gibbons v. Ogden, 22 U.S. 1, 228 (1824) (Johnson, J., concurring) (emphasis in original).

[11] Id. at 228–29; see also Japan Line, Ltd. v. Cnty. of L.A., 441 U.S. 434, 453–54 (1979).

[12] Kraft Gen. Foods, Inc. v. Iowa Dept. of Revenue and Fin., 505 U.S. 71, 79 (1992).

[13] Japan Line, 441 U.S. at 448–49.

[14] Kraft Gen. Foods, 505 U.S. at 80 (emphasis added).

[15] See Daniel K. Lee & Timothy P. Duane, Putting the Dormant Commerce Clause Back to Sleep: Adapting the Doctrine to Support State Renewable Portfolio Standards, 43 Envtl. L. 295 (2013); Steven Ferrey, Threading the Constitutional Needle With Care: The Commerce Clause Threat to the New Infrastructure of Renewable Power, 7 Tex. J. Oil, Gas & Energy L. 59 (2012); Carolyn Elefant & Edward A. Holt, The Commerce Clause and Implications for State Renewable Portfolio Standard Programs, Clean Energy States Alliance State RPS Policy Report (2011); Stephen C. Braverman, State Renewable Portfolio Standards and the Commerce Clause, 25 SPG Nat. Resources & Env’t 15 (2011); Trevor D. Stiles, Renewable Resources and the Dormant Commerce Clause, 4 Envtl. & Energy L. & Pol’y J. 33 (2009); Nathan E. Endrud, State Renewable Portfolio Standards: Their Continued Validity and Relevance in Light of the Dormant Commerce Clause, the Supremacy Clause, and Possible Federal Legislation, 45 Harvard J. on Legis. 259 (2008); Patrick R. Jacobi, Renewable Portfolio Standard Generator Applicability Requirements: How States Can Stop Worrying and Learn to Love the Dormant Commerce Clause, 30 Vt. L. Rev. 1079 (2006); Nancy Rader & Scott Hempling, Nat’l Ass’n of Regulatory Util. Comm’rs, The Renewables Portfolio Standard: A Practical Guide, A-2–4 (2001), available at http://www.scotthemplinglaw.com/files/naruc.org/Publications/rps.pdf; Kirsten H. Engel, The Dormant Commerce Clause Threat to Market-Based Environmental Regulation: The Case of Electricity Deregulation, 26 Ecology L.Q. 243, 268–81 (1999).

[16] See Coen & Thormeyer, supra note 6, at 543 (“Oregon, Washington, and Missouri do not include hydropower at all in their RPS, and other states, such as New Hampshire, California, and North Carolina, only make new hydropower projects eligible for inclusion in their renewable programs,” but exclude large-scale hydro projects).

[17] See Mary G. Powell, Treatment of Large Hydropower as a Renewable Resource, 32 Energy L.J. 553, 556 (2011).

[18] State policies excluding existing large-scale hydroelectric facilities from their definition of eligible renewable resources may also result in exclusion of additional hydroelectric output resulting from expansion of existing facilities. This impact, falling on in-state and out-of-state suppliers alike, may well be neutral in Commerce Clause terms, but the policy benefits are questionable. Expansion of existing hydroelectric projects is likely to be more economic than development of other sources of renewable energy. See Coen & Thormeyer, supra note 6, at 543. If the goal is to reduce carbon emissions, the exclusion becomes a costly choice for consumers.

[19] State Profile and Energy Estimates—Washington, 2014, U.S. Energy Info. Admin.,  http://www.eia.gov/state/?sid=WA (last updated July 17, 2014). Oregon similarly relies on hydroelectric energy for seventy percent of its energy needs. State Profile and Energy Estimates—Oregon, 2014, U.S. Energy Info. Admin., http://www.eia.gov/state/?sid=OR (last updated July 17, 2014).

[20] There are existing hydroelectric projects in all of these states. The Federal Energy Regulatory Commission posts a “Complete list of Issued Licenses” on its website. Licensing, Fed. Energy Regulatory Comm’n, http://www.ferc.gov/industries/hydropower/gen-info/licensing.asp (last updated Dec. 4, 2014).

[21] See Mary G. Powell, Treatment of Large Hydropower as a Renewable Resource, 32 Energy L.J. 553 (2011). See generally Coen & Thormeyer, supra note 6.

[22] See Coen & Thormeyer, supra note 6. Large-scale hydroelectric projects are considered to be those with a capacity of thirty or more megawatts. See Electric Power Research Inst., Assessment of Waterpower Potential and Development Needs 2-1 (2007), http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000000001014762&Mode=download.

[23] See Best & Co. v. Maxwell, 311 U.S. 454, 455–56 (1940) (“The commerce clause forbids discrimination, whether forthright or ingenious. In each case it is our duty to determine whether the statute under attack, whatever its name may be, will in its practical operation work discrimination against interstate commerce.”).

[24] Canada is a major exporter of electricity to the United States, most of which comes from hydroelectric facilities. See Charlotte Helston, Large Hydro, Energy bc (2012), http://www.energybc.ca/profiles/largehydro.html (last visited Mar. 6, 2015) (“60% of electricity produced in Canada is drawn from hydro. Only a portion of that hydroelectricity is used in Canada; the rest is exported for profit.”). And, while many of the most suitable sites for large-scale hydroelectric projects in Canada have already been developed, there still remains the potential for additional large-scale project development, particularly in Québec and British Columbia. Hydro-Québec, for example, broke ground in 2009 on the Romaine project, a 1550-megawatt hydroelectric project on the Romaine River. See Strategic Plan 2009-2013, Hydro–Québec 20 (2009), http://www.hydroquebec.com/publications/en/docs/strategic-plan/plan-strategique-2009-2013.pdf. The project is part of a larger plan to develop up to 4,500 megawatts of new large-scale hydroelectric facilities. Id. at 22. Further, in British Columbia, plans have been underway for several years to develop the Site C Clean Energy Project, a 1,100-megawatt hydroelectric facility on the Peace River in the northeastern portion of the province. See Site C Clean Energy Project, https://www.sitecproject.com (last visited Mar. 6, 2015). Manitoba also has some potential, although more limited, to develop new large-scale hydro projects. Manitoba Hydro’s current development plan contemplates the construction of  a 695 MW project and a 1,485 MW project that would support the province’s demand growth and exports to the U.S. See Development Plan and NFAT, Manitoba Hydro, http://www.hydro.mb.ca/projects/development_plan/index.shtml (last visited February 26, 2015).

[25] See Helston, supra note 24.

[26] See City of Philadelphia v. New Jersey, 437 U.S. 617, 627 (1978); Rocky Mtn. Farmers Union v. Corey, 730 F.3d 1070, 1089 (9th Cir. 2013).

[27] See Pew Center on Global Climate Change, Climate TechBook—Hydropower 5 (2011), http://www.c2es.org/docUploads/Hydropower_0.pdf (stating “[t]he best sites for large hydropower generation in the United States have already been developed,” and “the construction of new large hydropower dams is not considered a practical option for increasing hydropower generation due to the environmental impacts and unavailability of proper sites to develop for large-scale hydropower generation”); Lea Kosnik, The Potential of Water Power in the Fight Against Global Warming in the U.S., Energy Policy 1, 2 n.1 (2008), http://www.umsl.edu/~kosnikl/Saved%20Emissions.pdf (“We do not consider any potential coming from the construction of new large (i.e. traditional) hydropower dams.”); Water Use FAQ: What is hydroelectric power and how is it used?, U.S. Geological Survey, http://www.usgs.gov/faq/node/3248 (last modified Nov. 19, 2004) (“New large-scale hydroelectric facilities will be few and far between in the future as most of the prime locations to place large dams suitable for hydroelectric-power production have already been used.”).

[28] See Japan Line, 441 U.S. at 448–49.

[29] See Powell, supra note 17, at 556.

[30] Id. Vermont has since amended its laws to allow the inclusion of large-scale hydroelectric facilities as a renewable resource for RPS purposes, becoming the first state in the nation to do so. Id. at 553.

[31] See N.H. Rev. Stat. Ann. § 362-F:1 (2015) (emphasis added). There is both some protectionist consistency and some irony in New Hampshire’s position. Years earlier, the Supreme Court struck down the State’s legislation seeking to limit the export of energy from its own valuable large hydroelectric facilities for violating the Commerce Clause. New England Power Co. v. New Hampshire, 455 U.S. 331, 339 (1982).

[32] Coen & Thormeyer, supra note 6, at 544.

[33] Id.

[34] West Lynn Creamery, Inc. v. Healy, 512 U.S. 186, 204 (1994). States excluding new large hydroelectric projects from the definition of renewable resources may argue that their statutes do not single out Canadian energy sources in purpose or effect. The reason to advance such an argument is obvious: statutes that are discriminatory are subject to strict scrutiny under the dormant Commerce Clause, Or. Waste Sys., 511 U.S. at 101, while statutes alleged to burden interstate commerce come under the more lenient Pike balancing test, Pike v. Bruce Church, Inc., 397 U.S. 137, 142 (1970). In the author’s view, however, convincing a court that the restrictions on new large hydro facilities do not single out Canadian sellers is a pretty tough sell; they are the only entities selling power from facilities of this type.

[35] To be sure, while the exclusions are economic in nature, some legislators may have seen the exclusions as a deterrent, albeit an unconstitutional one, aimed at limiting the environmental harm from large hydro projects.

[36] It bears emphasis that when we are talking about Canadian hydroelectric facilities, we are not talking about ecological disasters like the Three Gorges Dam in China, which are subject to only limited environmental review. See Mara Hvistendahl, China’s Three Gorges Dam: An Environmental Catastrophe?, Scientific American (March 25, 2008), http://www.scientificamerican.com/article/chinas-three-gorges-dam-disaster/. As Hydro-Québec points out in its recent Strategic Plan, the Romaine Project now under way is subject to strict environmental review and was preceded by a required 2,500-page environmental impact statement. See Strategic Plan 2009–2013, Hydro–Québec, supra note 24 at 21.

[37] See Jennifer Runyon, Small States Grapple with Big Canadian Hydropower, Renewable Energy World, (March 7, 2011), http://www.renewableenergyworld.com/rea/blog/post/print/2011/03/small-states-grapple-with-big-canadian-hydropower; Erin Ailworth, Legislation raises question: What is clean energy?, Boston Globe, (February 26, 2014), http://www.bostonglobe.com/business/2014/02/26/legislation-would-increase-clean-energy-requirements-for-utilities/xrcj54IRKPudoYjmPZAFCK/story.html.

[38] Runyon, supra note 37. The reaction of Jake Brown, spokesman for the Vermont Natural Resources Council, to similar legislation in Vermont was not much different from Mr. Irwin’s:

So Vermont would be in many ways a domino falling and in our view a standards being dropped which is very unlike Vermont, Vermont is a place that has high standards and is proud of its high standards and what we’re doing here is really just slicing off a little piece of our reputation and giving it to Hydro Quebec.

Bob Kinzel, Lawmakers Pass Bill Making Hydro-Québec ‘Renewable’, Vermont Public Radio (May 7, 2010 5:49 PM), http://www.vpr.net/news_detail/87979/. Environmental groups opposing legislation that would relax the restrictions on large hydro in Connecticut and Wisconsin likewise articulated protectionist objections. The Sierra Club similarly criticized a 2011 Wisconsin bill allowing large hydro to qualify as a renewable resource, referring to it as the “Outsourcing Clean Energy Jobs to Canada Bill.” See Sierra Club – John Muir Chapter 2012 Legislative Scorecard, Sierra Club, http://www.sierraclub.org/sites/www.sierraclub.org/files/sce/wisconsin-john-muir-chapter/newsletters/SCJMC_2012_LegScorecard.pdf. In Connecticut, the Conservation Law Foundation warned that “RPS recognition of large-scale hydropower will merely serve to funnel ratepayer funds to foreign Canadian utilities for a resource that is already economically viable.” Letter from N. Jonathan Peress, Dir., Clean Energy and Climate Program, Conservation Law Found., to Debra Morrell, Connecticut Dep’t. of Energy and Envt. Protection, Bureau of Energy and Tech. Policy, regarding 2012 Comprehensive Energy Strategy for Connecticut at 8 (December 21, 2012) (on file with author).

[39] See West Lynn Creamery, 512 U.S. at 205 (“Preservation of local industry by protecting it from the rigors of interstate competition is the hallmark of economic protectionism that the Commerce Clause prohibits.”).

[40] Richard A Epstein, How Progressives Rewrote the Constitution 23 (Cato Institute, 2006).

[41] North American Agreement on Environmental Cooperation, U.S.-Can.-Mex., Sept. 14, 1993, 32 I.L.M. 1480, available at http://www.cec.org/Page.asp?PageID=1226&SiteNodeID=567 (last visited Mar. 19, 2015).

[42] Harvey L. Reiter, America’s Energy Future: So Who Are the Good Guys?, 151 Public Utilities Fortnightly,. no. 10 52, 56 (2013) (and sources cited therein).

[43] See, e.g., John Upton and Climate Central, Solar Farms Threaten Birds, Scientific American (August 27, 2014), http://www.scientificamerican.com/article/solar-farms-threaten-birds/ (describing how thousands of birds have crashed into or been incinerated by large solar arrays in Arizona and Nevada); Rose Eveleth, How Many Birds Do Wind Turbines Really Kill, Smithsonian.com (December 16, 2013), http://www.smithsonianmag.com/smart-news/how-many-birds-do-wind-turbines-really-kill-180948154/?no-ist (citing estimates that “somewhere between 140,000 and 328,000 birds die each year from collisions with wind turbines”).

[44] See Todd Woody, Water Use by Solar Projects Intensifies, N.Y. Times (Oct. 27, 2009), http://green.blogs.nytimes.com/2009/10/27/water-use-by-solar-projects-intensifies/?_r=0.

[45] Alan S. Blinder, Free Trade, in The Concise Encyclopedia of Economics (David R. Henderson ed., 2d ed. 2007), available at http://www.econlib.org/library/Enc/FreeTrade.html.

[46] Reiter, supra note 42, at 59, 69.

[47] See Vt. Stat. Ann. tit. 30, § 8002(2)(C) (West 2014).

[48] See Wis. Stat. Ann. § 196.378 (West 2014) (under Wisconsin’s law, removal of the limitation on treating large-scale hydroelectric facilities as renewable will take effect on December 31, 2015).

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The Regulatory Challenge Of Distributed Generation

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David B. Raskin*   

I.   Introduction

Recent published reports point toward a growing conviction that the demand for utility service from the U.S. electric grid may soon decline, perhaps substantially, due to the expanding use of distributed generation.[1] One report prepared by a division of Citigroup describes the improving economics of distributed solar power, which the authors expect will continue.[2] A second Citigroup report projects reductions in the demand for utility service in developed markets of up to fifty percent by 2050.[3] Favorable projections for distributed generation, however, depend on assumptions about technological change that may turn out to be overstated, and even if distributed generation grows substantially, millions of homes and businesses will continue to rely on the electric grid for many decades.[4]

Germany has gone further to promote distributed generation[5] than any other industrialized nation, and its experience provides a cautionary tale. More than a decade after Germany initiated its Energiewende,[6] the average residential price for electricity is almost 36 cents per kWh,[7] and rates are projected to rise another thirty to fifty percent in the next ten years.[8] Without a change in policy, German residential electric rates may therefore approach 50 cents per kWh by the end of this decade. In contrast, the average residential rate in the U.S. is approximately 12.5 cents per kWh.[9] Because the average U.S. residence uses approximately 1,000 kWh of electricity per month,[10] the current German rate would be equivalent to an average household tax of $3,000 per year. Rates anywhere near the levels being experienced in Germany would be unacceptable in the U.S.[11]

Even with extraordinarily high and increasing electric rates, aggregate carbon dioxide emissions by the German electric sector are rising.[12] In contrast, U.S. emissions are falling even though renewables constitute a much smaller percentage of the electric energy mix in the U.S.[13] The stability of the German grid is also being put at risk: it has relied more heavily on variable, renewable generation at the same time that grid resources capable of rapidly balancing supply and demand have been shutting down due to anomalous market price signals.[14] Energiewende has also taken a toll on the utility companies that may have to make the grid investments to fix these operating problems. Equity values for Germany’s biggest utilities have fallen by fifty percent or more over the past three years.[15]

While Germany struggles with Energiewende, the growth of distributed generation in the U.S. is being fueled by a controversial regulatory practice known as net metering. If distributed generation comes to play a significant role, the loss of demand for service from the grid may eventually make it difficult for the owners of grid assets to recover their costs, creating what the utility industry calls “stranded costs.” This Article explores the debate over net metering and then turns to the longer-term prospect of having to address potential stranded costs produced by the expanded use of distributed generation.

II.   Net Metering: The Current Battlefield

Most renewable generation in the U.S. is subsidized through investment or production tax credits.[16] This Article focuses on an additional subsidy to distributed renewable generation alone that exists as a result of “net metering” as applied in about forty states. Under net metering, retail customers (including commercial and industrial customers) can offset their electricity purchases from the grid with energy generated behind the retail meter, such as from rooftop solar panels. In most of the states that allow net metering, the credit equals the bundled retail rate. The credit applies not only to foregone consumption but also—with limited exceptions—to the energy generated from behind the meter in excess of the customer’s own use and delivered to the utility.[17]

Net metering therefore values the energy produced by distributed generators at the bundled retail rate for electricity. The bundled retail rate includes, in addition to the cost of producing electric energy, the costs associated with investment in and operation of transmission and distribution facilities and other costs incurred to ensure reliability and fund public policy initiatives endorsed by utility regulators. As noted above, the average residential price of electricity (the average bundled rate) is currently around 12.5 cents per kWh.[18] According to published data as of November 2013, the market price of energy from grid-connected[19] generators is averaging, in most locations, between 2 and 3 cents per kWh during off-peak periods and between 4 and 5 cents per kWh during on-peak periods.[20] Recent sales of grid-connected renewable energy have been priced near or below 3 cents per kWh.[21] Therefore, net metering allows the owners of distributed generation to effectively sell their energy at prices between two and six times the market price for energy.

Grid-connected renewable generators are paid the much lower market price for their energy, so the issue is not, as advocates of distributed generation allege, merely about promoting “clean” energy. A grid-connected solar generator at the same location as a distributed solar generator receives a fraction of the compensation for providing energy using similar—and equally clean—technology.[22] Grid-scale solar generation is actually more efficient, so net metering provides a huge subsidy to a less efficient form of renewable energy.

Utilities point out that the differential is paid by other retail customers. Because virtually all retail service is billed based on energy usage, net metering causes a re-allocation of transmission, distribution, and reliability costs to those customers who do not own distributed generation. Yet, the owners of distributed generation continue to rely on utility service from the grid for back-up and supplemental energy (for example, at night and when it is cloudy). Presently, the use of distributed generation in the U.S. is sufficiently limited that the cost-shifting effects are minor. However, subsidies this large can induce rapid changes. A report recently issued by the California Public Utilities Commission forecasts that net metering will cost the State $1.1 billion per year in 2020.[23] It also finds that the average net metering customer in California has an income almost twice the state’s average, [24] confirming claims that net metering entails a wealth transfer from low- to high-income consumers.

Net metering raises a number of legal issues that are just beginning to be explored. The definition of “net metering service” in the Energy Policy Act of 2005 indicates that Congress did not endorse the subsidy described above.[25] Section 111(d)(11) of the Public Utility Regulatory Policies Act (PURPA)[26] was added in 2005 to a list of retail ratemaking practices that state utility commissions are required to evaluate for use in their jurisdictions. This provision defines “net metering service” as follows:

Net Metering – Each electric utility shall make available upon request net metering service to any electric consumer that the electric utility serves. For purposes of this paragraph, the term “net metering service” means service to an electric consumer under which electric energy generated by that electric consumer from an eligible on-site generating facility and delivered to the local distribution facilities may be used to offset energy provided by the electric utility to the electric consumer during the applicable billing period.[27]

Under this definition, “electric energy” generated by a retail customer’s on-site facility may be used to offset “energy” provided by the utility. The language strongly implies that Congress meant only to ensure that consumers would receive an appropriate credit for the energy supplied from on-site generation and not a credit based on the bundled retail rate that includes costs associated with transmission, distribution, and reliability. If this is correct, net metering as applied in most states is inconsistent with this part of PURPA.[28]

In 2002, the Supreme Court of Ohio addressed this very issue in connection with interpreting Ohio legislation that required public utilities to offer net metering.[29] In that case, FirstEnergy proposed a net metering regime under which net metered customers would receive a credit for energy supplied from on-site generation based on the unbundled generation component of the retail rate.[30] This proposal was rejected by the Ohio Public Utilities Commission, which directed that FirstEnergy offer a credit based on the full bundled retail rate.[31] The Ohio Supreme Court held that FirstEnergy had correctly applied statutory language requiring utilities to provide a credit for the “electricity” produced by on-site generators by offering to credit only the generation component of the retail rate.[32] The Court found that FirstEnergy was correct in contending that a net meter customer “does not provide transmission, distribution or ancillary services,” and therefore the term “electricity” in the statute did not require a credit for the costs associated with these other unbundled services.[33]

Net metering also appears to be inconsistent with provisions of PURPA that were designed to protect electric consumers from cross-subsidization. Under PURPA, utilities are required to purchase energy from qualifying “small power production” facilities that meet eligibility standards established in the law.[34] Under FERC regulations, retail customers that own on-site generators with a maximum net generating capacity of less than 1 MW are permitted to self-implement PURPA’s mandatory purchase requirement without any notification to or approval from FERC.[35] Most retail customers using net metering rely on the mandatory purchase requirement to require their host utilities to purchase their energy.[36] Absent the PURPA requirement, utilities would generally have no obligation to buy energy from distributed generators because the Federal Power Act[37] (the law that applies in the absence of PURPA) does not obligate utilities to purchase energy at wholesale.[38]

PURPA, however, while requiring utilities to buy, also caps the price paid to qualifying facilities at the purchasing utility’s “avoided cost,” which is defined as the cost of energy that would have been supplied from the utility’s own system if the energy had not been supplied by the qualifying facility.[39] Because net metering compensates owners for the energy supplied from distributed generation at the utility’s bundled retail rate, this practice would appear to violate the avoided cost rate cap that is based on the cost of energy alone.

The FERC, however, permits net meter customers to avoid this price cap. The FERC holds that unless a retail customer with on-site generation is a net supplier of energy to the grid over the state retail billing period (almost always one month), no sale takes place under PURPA or the Federal Power Act, even if there are substantial deliveries of energy to the grid during the month.[40] In the absence of a “sale” to the utility, FERC deems that no mandatory purchase of energy is taking place under PURPA and the avoided cost price cap does not apply.[41]

The FERC’s theory, that the existence of a “sale” can be determined by netting metered inflows and outflows over the course of a month, was recently rejected in two appellate cases involving FERC’s use of this same theory to determine whether a retail sale has occurred when generators acquire energy for station service purposes, the mirror image of the net metering situation.[42] In these two cases, the D.C. Court of Appeals held that netting could not be used to determine whether a sale has taken place and that there is a sale whenever energy is delivered from the generator to the utility and vice versa.[43] The FERC’s disclaimers of jurisdiction in MidAmerican and SunEdison may therefore be subject to a renewed challenge, which, if successful, would require net metering rules to be changed at the state level.

This same “netting” theory allows FERC to avoid facing the fact that the prices inherent in net metering are discriminatory. The Federal Power Act prohibits charges for wholesale energy that are “unduly discriminatory,”[44] but this prohibition only applies if there is a FERC-jurisdictional wholesale transaction. MidAmerican Energy and SunEdison therefore provide a rationale for FERC to avoid addressing the huge differential between the prices paid to distributed and grid-connected generators for the energy they supply.

From both economic and environmental perspectives, energy from distributed generation is no more beneficial than other forms of renewable generation. Energy available to meet electric load, whether generated behind the retail meter or from grid-connected generation, provides equivalent value to the electric system. Therefore, the price discrimination inherent in net metering cannot be justified based on differences in the value of the services offered. If anything, distributed solar is less valuable than most energy from grid-connected generators because the energy output of solar facilities varies uncontrollably. Consequently, utilities must have sufficient grid-connected capacity on hand to supply the entire load when solar generation is non-productive. For the same reason, retail customers with distributed generation require access to grid-supplied energy up to their full load at unpredictable times.[45] Indeed, solar generation has a pernicious effect on energy markets because energy from solar generators tends to suppress energy market prices during peak-load periods, providing less revenue for grid-connected generation and falsely signaling to the market that grid-connected generation that is needed for reliability is no longer economic.[46]

In conclusion, net metering as currently practiced in most states provides a huge subsidy to distributed generators over and above the tax subsidy provided to all renewable generation, discriminates against all forms of grid-connected generation (including renewables), forces an inappropriate re-allocation of the costs of the grid to remaining (and disproportionately lower income) customers, and sends a faulty price signal that can cause under-investment in (or early shut down of) grid-connected generation that is needed for real-time balancing purposes and to meet peak demands. These same problems—in larger scale—are among the primary causes of Germany’s growing dysfunction.

III.   The Return of Stranded Costs

Broadly speaking, the current dispute over net metering is about managing the growth of distributed generation during the period when growth is being fueled by subsidies. If projections such as those made by Citigroup are correct, the cost of energy from distributed generation will decline, eventually making it competitive with energy from the grid without subsidies, and the pace of growth will accelerate. At some point, distributed generation could be married to behind-the-meter storage capability, permitting customers to disconnect from the grid or significantly limit their use of utility service. Investments in distributed generation combined with storage should expand rapidly when and if the combined cost of distributed energy and storage reaches parity with the cost of bundled service from the grid.

In this scenario, as the demand for service from the grid declines and utilities need to recover the cost of the grid from a smaller customer base, utilities will have to respond by filing to raise rates. While this is occurring, a large body of customers will remain dependent on electricity from the grid for a considerable period of time since many customers may not have the resources to install distributed generators and others may choose to take their electric service from the grid.

Even as this possible transition approaches, billions of dollars of grid investments are being made, mostly in response to regulatory mandates.[47] As the use of distributed generation grows, investors in grid assets will demand that regulators provide assurance that their investments will be recoverable over time with a reasonable return. Otherwise, the cost of capital will rise, exacerbating the problem of rising rates during the transition, and in a worst case making it impossible for utilities to raise the capital needed to serve remaining customers and compensate investors for their prior investments in the grid.

Around the turn of the century, the utility industry faced the prospect that investments in generation might be unrecoverable. In those jurisdictions that permitted “retail choice” of electricity suppliers, utility generation was unbundled and re-priced to market. This competitive transformation produced debates over whether utilities were entitled to recover the costs associated with prior generation investments from departing customers when sunk costs exceeded the revenues recoverable at market prices. The differential was known as “stranded costs.”

Utilities argued that they were entitled by law to recover their stranded costs pursuant to an implicit bargain with the government under which utilities had assumed an obligation to serve the public in return for assurance that they would be compensated for their prudent investments made to meet that obligation. Along with many scholars, utilities argued that the law recognized this “regulatory compact” and that failure to permit the recovery of stranded costs represented an unconstitutional taking of utility property.[48] Others argued that no such legal right exists and that allowing utilities to recover their stranded costs would be inconsistent with the transition to competition.[49]

In the states that endorsed retail choice, legislative or regulatory compromises were reached in which utilities recovered most of their stranded costs. The underlying legal question was never resolved decisively in the courts. The stranded cost issue will be different in the context of utility loss of demand to distributed generation. In this context, stranded cost issues will not appear at one point in time (such as a legislative determination to permit retail customer choice) but will emerge gradually as utilities and regulators respond to reductions in aggregate demand for utility service. The stranded cost issue may also include stranded investment in transmission and distribution assets as well as generation. Further, stranded cost recovery will have to be addressed in the context of a declining utility customer base that may ultimately become too small to support recovery. In the last round of stranded costs, customers changing power suppliers remained as transmission and distribution customers of the utility and stranded costs could be recovered in the rates for these unbundled services.

A.  Cost Recovery for Regulated Assets

Assuming distributed generation becomes economical without subsidies, retail customers will be making independent decisions about whether to reduce or jettison utility service, and these decisions will occur over time as the relative economics of grid-produced and distributed electricity change. The stranded cost issue is therefore likely to arise in individual rate proceedings as utilities file to increase their rates to offset the effects of declining demand and regulators respond by requiring offsetting cost reductions to cabin these rate increases to remaining captive customers. As this process unfolds, history teaches that there will be disputes over the prudence of past utility expenditures and over whether particular assets remain “used and useful” and thus eligible for cost recovery.

The Supreme Court’s decision in Duquesne Light Co. v. Barasch holds that a utility’s Constitutional right to recover its costs to serve the public is not infringed by regulatory decisions disallowing individual items of cost.[50] An unlawful “taking” occurs only when the overall level of rates produces insufficient revenue to satisfy the “end-result” test established in FPC v. Hope Natural Gas Co.[51] Hope held that overall rate levels “which enable a company to operate successfully, to maintain its financial integrity, to attract capital, and to compensate its investors for the risk assumed . . . ” are sufficient to pass Constitutional muster.[52] The Hope test is fairly subjective and may not produce rates that are attractive to investors. Duquesne suggests that stranded cost issues will have to be addressed through rate litigation, which means the availability of relief to distressed utilities may be delayed.[53] Without legislation, moreover, the remaining customer base will eventually become too small, forcing utilities to try and convince regulators to permit them to charge exit fees to departing customers. For these reasons, substantial pressure will arise to resolve stranded cost recovery issues through legislation. Legislative fixes will be a hard sell politically, but legislators may be convinced to act in order to prevent important energy policy issues from being decided in the courts.[54]

In determining which facilities remain used and useful, regulators will have to balance reliability and environmental effects as well as economics. They will also have to address complex competing interests. For example, utilities supply power using a combination of owned generation and purchases in the form of FERC-jurisdictional power purchase agreements (PPAs), most of which are the product of regulatory mandates. Federal law protects FERC-jurisdictional PPAs by requiring state regulators to pass through the costs incurred by utility buyers in their retail rates.[55] But this “trapped cost” protection will be a two-edged sword for utilities that face premature retirement of their own generation while continuing to pay third parties for purchased power. FERC may therefore face a host of contract termination disputes. The transition will be made more difficult by the fact that most utility-owned generation is subject to state regulation, PPAs are regulated by FERC, and substantial generation is publicly owned and not subject to traditional rate regulation.

Generation cost recovery is likely to be under pressure before transmission and distribution. For the most part, the electric delivery system operates as an integrated network, and it will be difficult to identify specific assets that are no longer required as demand declines. Nonetheless, a substantial portion of the cost of electricity consists of investments in transmission and distribution, and a regulator under pressure to reduce rates would eventually have to pay attention to the cost of these facilities. Stranded transmission and distribution cost issues will play out simultaneously at FERC (which regulates most unbundled transmission) and in state proceedings (for bundled transmission and local distribution) unless Congress changes jurisdictional responsibilities.[56]

Disputes will likely arise over which assets should be targeted for early retirement. The interstate transmission grid, for example, is an integrated network of facilities owned by a large number of entities.[57] One can imagine a form of competition among transmission asset owners to protect their assets and avoid stranded costs. Most publicly-owned transmission is not subject to FERC or state jurisdiction, which will further complicate the process.

As this process unfolds, utility investors will be watching. As cost recovery uncertainty rises, debt and equity investors will demand higher returns, making it more expensive to maintain a reliable grid and putting further upward pressure on utility rates. At some point, the risks could be large enough that investors will not provide capital on acceptable commercial and regulatory terms, and investment in the grid will become problematic, even as many consumers continue to rely on it.

B.  Unregulated Generation

In regions where utilities have already divested their generation to merchant power producers, capacity and energy is transacted in wholesale markets under the control of RTOs, subject to overarching FERC regulation. Market forces will therefore play a significant role in determining which generators survive as demand declines. The owners of unregulated generation have assumed the market risk and are much less likely to have valid stranded cost claims.

But electricity markets will only provide a partial solution. With recent reductions in natural gas costs and flat demand, grid-connected generation is already under considerable economic pressure, and regulators are being asked to approve additional revenue streams to support reliability and new investment. In response to disputes over market rules, regulators are making critical decisions on the economic margin. Therefore, even where generation is subject to market forces, the future portends complex regulatory disputes over how wholesale markets should be organized to respond to reductions in the demand for energy from the grid. At the core of these disputes, an enduring tension will exist between economics, reliability, and fairness.

IV.   Conclusion

Once a sizable number of customers have invested in distributed generation in response to the subsidies afforded under net metering, changing the economic rules will be difficult, both because some customers will have relied on subsidies to make their investments and others will want the same opportunities as their neighbors. Policymakers therefore should not long defer addressing the consequences of providing these subsidies in order to promote distributed generation over other alternatives. What may appear politically attractive in its early stages can quickly become a regulatory and political quagmire, as the Germans are learning. The U.S. will not countenance electric rates anywhere close to German levels, nor an electric system that is not reliable. Over the long term, any required unwinding of the utility-owned grid due to distributed generation will be extraordinarily complex and will raise many novel and intractable legal and policy issues.

 

 

Preferred citation: David B. Raskin, The Regulatory Challenge of Distributed Generation, 4 Harv. Bus. L. Rev. Online 38 (2013), https://www.hblr.org//?p=3673.

* David Raskin is a partner in the Washington, DC office of Steptoe & Johnson LLP. He has represented stakeholders in the electric power industry for more than thirty years. During this time, he has been involved in most of the significant federal regulatory initiatives designed to increase competition in the electric industry and has assisted clients in managing the unprecedented changes that have occurred in recent decades.

[1] E.g., Diane Cardwell, On Rooftops, a Rival for Utilities, N.Y. Times, July 26, 2013, http://www.nytimes.com/2013/07/27/business/energy-environment/utilities-confront-fresh-threat-do-it-yourself-power.html; Peter Kind, Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric Business, Edison Electric Institute (Jan. 2013), www.eei.org/ourissues/finance/Documents/disruptivechallenges.pdf‎.

[2] Citi Research, Rising Sun: Implications for US Utilities (Aug. 8, 2013), http://www.wecc.biz/committees/BOD/TEPPC/SPSG/Lists/Events/Attachments/706/CITI-Rising%20Sun%20Implications%20for%20US%20Utilities.pdf.

[3] Jason Channell et al., Energy Darwinism: The Evolution of the Energy Industry, Citi Global Perspectives & Solutions 73-75 (Oct. 2013), https://ir.citi.com/Jb89SJMmf%2BsAVK2AKa3QE5EJwb4fvI5UUplD0ICiGOOk0NV2CqNI%2FPDLJqxidz2VAXXAXFB6fOY%3D.

[4] Even if Citi’s aggressive prediction of fifty percent demand reduction by 2015 turns out to be accurate, that prediction leaves fifty percent of electric load dependent on grid service.

[5] In this Article, references to “distributed generation” refer to energy sources located behind the retail meter or connected to a micro grid, where the intent is to remove some load or demand from the system of integrated electric generation, transmission, and distributed facilities that comprise what is referred to in this Article as the “grid.”

[6] Energiewende, or energy transformation, is the product of the German Renewable Energy Act of 2000 (Erneuerbare-Energien-Gesetz) that put in place substantial subsidies for distributed generation and grid-connected renewables. See General Information: Transformation of Our Energy System, Ger. Fed. Ministry for the Env’t, Nature Conservation and Nuclear Safety, www.bmu.de/P118-1/ (last visited Nov. 24, 2013).

[7] Jesse Morris, How Germany’s Solar Evolution Impacts America, Earth Techling (Oct. 12, 2013), http://www.earthtechling.com/2013/10/how-germanys-solar-evolution-impacts-america. Ironically, this article laments the fact that the German feed-in tariff rate for distributed solar is only 20 cents per kWh, well below the full retail rate.

[8] Institute for Energy Research, Germany’s Energy Policy: Man-Made Crisis Now Costing Billions (Oct. 30, 2012), http://www.instituteforenergyenergy research.org/10/20/2012. Many Germans claim they can no longer afford to buy electricity. Germany’s Energy Poverty: How Electricity Became a Luxury Good, Spiegel Online Int’l (Sept. 4, 2013), http://www.spiegel.de/international/germany/high-costs-and-errors-of-german-transition-to-renewable-energy-a-920288.html.

[9] Energy Info. Admin., Table 5.6.A. Average Retail Price of Electricity to Ultimate Customers by End-Use Sector, (Nov. 20, 2013), http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_5_6_a.

[10] Energy Info. Admin., How Much Electricity Does an American Home Use?, http://www.eia.gov/tools/faqs/faq.cfm?id=97&t=3 (last updated Mar. 19, 2013).

[11] Germany’s Environment Minister, Peter Altmaier, has acknowledged that Germany has overdone the subsidies and needs to cut them back. Diarmaid Williams, Altmaier says German energy transition could cost $1.34trn, Power Energy International (Feb. 21, 2013), http://www.powerengineeringint.com/articles/2013/02/Altmaier-says-German-energy-transition-could-cost-134trn.html; Minister Altmaier: EEG Cuts Needed—or Energiewende Costs Will Reach Trillion Euro Mark by 2040, German Energy Blog (Feb. 20, 2013), http://www.germanenergyblog.de/?p=12278.

[12] Spiegel Online Int’l, supra note 8; Max Luke, Jessica Lovering & Alex Trembath, Trash, Trees and Taxes: The Cost of Germany’s Energiewende, Energy Collective (Sept. 16, 2013), http://theenergycollective.com/maxluke/274041/trash-trees-and-taxes.

[13] An environmental critique of Energiewende can be found in Will Boisvert, Green Energy Bust in Germany, Dissent (2013), http://www.dissentmagazine.org/article/green-energy-bust-in-germany.

[14] Tilting at Windmills, Economist, June 15, 2013, available at http://www.economist.com/news/special-report/21579149-germanys-energiewende-bodes-ill-countrys-european-leadership-tilting-windmills.

[15] How to Lose Half a Trillion Euros, Economist, October 12, 2013, available at http://www.economist.com/news/briefing/21587782-europes-electricity-providers-face-existential-threat-how-lose-half-trillion-euro.

[16] German subsidies primarily take the form of “feed in tariffs” that guarantee minimum per kWh payments to those employing favored technologies, which are paid out of a pool funded by consumers. See Stefan Nicola, German Industry Wants End of Feed-in Tariff on Rising Power Cost, Bloomberg (Sep 19, 2013, 5:53 AM), http://www.bloomberg.com/news/2013-09-19/german-industry-wants-end-of-feed-in-tariff-on-rising-power-cost.html.

[17] As discussed below, the Federal Energy Regulatory Commission (FERC) has disclaimed jurisdiction over energy supplied from behind-the-meter distributed generation so long as the customer does not supply more excess energy than it acquires from the grid over the course of a monthly retail billing period.

[18] Energy Info. Admin., Table 5.6.A, supra note 9.

[19] This Article refers to generators that are connected on the utility side of the customer meter as “grid-connected generation” for ease of reference. This is a misnomer, however, because all generation, including generation located on a retail customer’s property on the customer side of the meter, is connected to and part of the electric grid. Electricity does not recognize the difference in location; at all times sufficient energy must be supplied to meet the aggregate demand of all users, and the system must be kept in precise balance (supply equaling demand) in order to prevent outages and serious damage to facilities.

[20] See Platts, Megawatt Daily, at 2-10 (November 27, 2013).

[21] American Wind Energy Association, The Cost of Wind Energy in the U.S., http://www.awea.org/Resources/Content.aspx?ItemNumber=5547 (last visited Nov. 24, 2013).

[22] The analysts at Citi put it succinctly: “While residential solar has the advantage of competing against higher residential electricity prices, merchant utility scale solar must compete against wholesale power prices.” Citi Research, supra note 2 at 21.

[23] See Cal. Pub. Utils. Comm’n, California Net Energy Metering (NEM) Draft Cost-Effectiveness Evaluation (2013), available at http://www.cpuc.ca.gov/NR/rdonlyres/BD9EAD36-7648-430B-A692-8760FA186861/0/CPUCNEMDraftReport92613.pdf.

[24] Id. at 110.

[25] Energy Policy Act of 2005, Pub. L. No.109-58, sec. 1251, § 111(d), 119 Stat. 962 (codified as amended at 16 U.S.C. 2621(d)(11)).

[26] See id.; Pub. Util. Reg. Policies Act of 1978, Pub. L. No. 95-617, § 111(d), 92 Stat. 3117, 3142-43 (codified as amended at 16 U.S.C. § 2621(d)(10)(E)(11) (2006)).

[27] Energy Policy Act § 111(d); 16 U.S.C. § 2621(d)(10)(E)(11).

[28] Congress also did not define what it meant by “delivered to the local distribution facilities” in this provision. It may have intended the energy credit to apply only to energy in excess of the customer’s on-site use, or it may have intended that all energy produced on-site be treated as energy provided to the grid because all such energy substitutes energy that would otherwise be supplied from the grid. Either way, the definition provides only for an energy credit, which is not what occurs in most jurisdictions.

[29] FirstEnergy Corp. v. Pub. Utils. Comm’n of Ohio, 768 N.E.2d 648 (Ohio 2002).

[30] Id. at 650.

[31] Id.

[32] Id. at 652.

[33] Id.

[34] Pub. Util. Reg. Policies Act § 210 (codified at 16 U.S.C. § 824a-3(a) (2006)). FERC regulations refer to these as “qualifying facilities.” 18 C.F.R. § 292.101(b)(1).

[35] 18 C.F.R. § 292.203(d) (2010).

[36] See Stephanie Watson, How Net Metering Works, How Stuff Works, http://science.howstuffworks.com/environmental/green-science/net-metering2.htm (last visited Nov. 24, 2013).

[37] 16 U.S.C §§ 791a-825r.

[38] From the earliest days of Federal Power Act jurisprudence, courts have emphasized that wholesale power transactions under the Federal Power Act are voluntary. Fed. Power Comm’n v. Sierra Pac. Power Co., 350 U.S. 348 (1956). In organized Regional Transmission Organization (RTO) markets, any generator that signs a service agreement with RTO is permitted to bid its energy into the market and, if dispatched, gets paid the locational marginal cost of energy, even if the generator does not have a contract with a specific buyer.

[39] Am. Paper Inst. v. Am. Elec. Power Serv. Corp., 461 U.S. 402, 404 (1983).

[40] See MidAmerican Energy Co., 94 F.E.R.C. P 61,340 (2001); Sun Edison LLC, 129 F.E.R.C. P 6,1146 (2009).

[41] Id.

[42] See S. Cal. Edison Co. v. FERC, 603 F.3d 996 (D.C. Cir. 2010); Calpine Corp. v. FERC, 702 F.3d 41 (D.C. Cir. 2012).

[43] See S. Cal Edison Co. 603 F.3d at 1000-01; Calpine Corp. 702 F.3d at 45.

[44] 16 U.S.C. § 824e(a).

[45] California is attempting to overcome this issue by requiring utilities to purchase storage capacity using new technologies to help balance supply and demand. Order Instituting Rulemaking Pursuant to Assembly Bill 2514 to Consider the Adoption of Procurement Targets for Viable and Cost-Effective Energy (published October 17, 2013), Cal. Pub. Utils. Comm’n, 2013 Cal. PUC LEXIS 569, available at http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M078/K912/78912194.PDF. Whether these alternative technologies will become available in sufficient quantities and at a reasonable cost to replace balancing generation from the grid, and how long this may take, is unknown.

[46] The Economist notes: “Renewables can depress wholesale prices, e.g. when the sun creates a midday jolt. This discourages investors in the flexible, gas-powered generation needed to provide backup for windless, cloudy days.” Energiewinde, Economist, July 28, 2012, at 3. Citi Research, noting that solar production causes lower utilization rates for conventional generation plants, concludes: “This would in a perfect economic world lead to the closure of some higher heat rate gas plants, but the problem of course is that much of this generation capacity needs to remain to cover lost generation on less sunny days and at night, and through the winter . . . .” Citi Research, supra note 2, at 17.

[47] For example, the electric industry is investing significant sums in response to state laws imposing renewable portfolio standards. Large additional investments are being made to modernize the transmission and distribution systems and incorporate so-called “smart grid” technologies. One utility executive recently noted that half the existing transmission grid is more than fifty years old, so sizable investments to sustain it are inevitable. Lisa Barton, IHS The Energy Daily, September 26, 2013, at 14. Several northeastern states are requiring utilities to invest in “hardening” their systems in response to recent storm-related outages. See Diana Cardwell et al., Hurricane Sandy Alters Utilities’ Calculus on Upgrades, N.Y. Times, Dec. 28, 2012, at B1. Since 2005, the utility industry has also been subject to mandatory reliability standards approved by the FERC that require significant ongoing investments in the grid. 16 U.S.C. § 824o (2005).

[48] See, e.g., J. Gregory Sidak & Daniel F. Spulber, Deregulatory Takings and Breach of the Regulatory Contract, 71 N.Y.U. L. Rev. 851 (1996).

[49] See, e.g., Susan Rose-Ackerman & Jim Rossi, Disentangling Deregulatory Takings, 86 Va. L. Rev. 1436 (2000).

[50] 488 U.S. 299, 314-15 (1989) [hereinafter Duquesne].

[51] 320 U.S. 591, 602-03 (1944) [hereinafter Hope].

[52] Id. at 605.

[53] The takings issue will recur if demand declines further over time. If demand declines after rates have been set, utilities will once again under-recover their costs, forcing them to file for another round of rate increases to offset the effect of the loss of load since the prior rate case. Utilities will be playing

“catch-up” to get the revenues needed to recover their costs and attract investment.

[54] Assuming much of the utility industry will have moved into other business lines, including distributed generation, legislators could be less inclined to provide full stranded cost relief in these circumstances.

[55] See Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 970 (1986); Entergy La., Inc. v. La. Pub. Serv. Comm’n, 539 U.S. 39, 48 (2003).

[56] In Texas, the Public Utility Commission of Texas (PUCT) regulates all of these functions. In other states where retail rates remain bundled, states will have most of the control over this process for both transmission and distribution assets, unless the FERC chooses (or is forced) to assume jurisdiction over interstate transmission costs that are bundled into retail rates pursuant to the Supreme Court’s opinion in New York v. FERC, 535 U.S. 1 (2002).

[57] FERC has recently decided that more entities should be eligible to build and own transmission facilities. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, FERC Stats. & Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), appeal docketed, S.C. Pub. Serv. Auth. v. FERC, No. 12-1232 (D.C. Cir. 2012).

 

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Investing in U.S. Pipeline Infrastructure: Could the Proposed Master Limited Partnerships Parity Act Spur New Investment?

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Linda E. Carlisle, Daniel A. Hagan and Jane E. Rueger*

The so-called “shale revolution” has upset traditional notions of supply and demand centers for natural gas and crude oil. Demand centers in the Northeast traditionally needed to import natural gas or oil from distant supply centers, such as Texas or Louisiana. However, major plays located near these demand centers, such as the Marcellus shale, are causing directional flows on existing pipelines to change. In addition, these plays have spurred the need for additional pipeline infrastructure development to transport crude oil and natural gas liquids from major shale plays in the Northeast and the Midwest to processing and manufacturing facilities that currently exist or are under development in Texas and Louisiana.

This Article explores combining the traditional oil and gas pipeline structure with solar electric generation to: (1) increase the return on pipeline investments by making the income from a solar electric generation business available to pipeline operators; and (2) lower the cost of operating the pipeline. After a brief overview of the current state of U.S. pipeline infrastructure, this Article describes the structure generally used for current pipeline investment and pending legislation, which would make the structure available to solar electric generation businesses. The Article then explores the potential benefits of combining solar generation and pipeline transportation businesses if the pending legislation passes.

Overview of the Current State of U.S. Pipeline Infrastructure

The past decade has brought sweeping change to the oil and gas industry in the United States. Technological developments in drilling and hydraulic fracturing have allowed extraction of large volumes of shale gas and tight oil that were previously economically infeasible to produce. With respect to natural gas, tight oil and shale gas accounted for forty percent of the total U.S. natural gas produced in 2012.[1] The U.S. Energy Information Administration (EIA) projects natural gas production in the United States will increase from 23.0 trillion cubic feet in 2011 to 33.1 trillion cubic feet by 2040, a forty-four percent increase almost entirely due to projected growth in shale gas production.[2] As of June 2013, EIA ranks the United States fourth in the world with respect to volume of technically recoverable shale gas resources[3] and projects that the United States may become a net exporter of natural gas in years to come.[4] Crude oil production has similarly increased; EIA ranks the United States second in the world with respect to volume of technically recoverable shale oil,[5] and crude oil production from tight plays accounted for nearly all 847,000 barrels per day increase in production in 2012 compared with 2011.[6] This is by far the largest growth in crude oil production in any country.[7]

Development of the infrastructure necessary to fully utilize the wealth of shale oil and gas reserves in the United States has been slow to materialize. Pipelines, particularly large diameter, long-distance interstate pipelines, are very expensive to build. By some recent estimates, onshore pipeline construction costs in the United States can be an average cost-per-mile of $3.1 million.[8] A recently proposed interstate natural gas pipeline is expected to cost approximately $3 billion to build.[9] Moreover, pipelines have a long construction lead-time: it often takes years to work through planning, siting, and obtaining regulatory approvals, prior to beginning construction. Developers have often found it difficult to attract the kind of long-term firm commitments that are necessary to support investment in pipeline infrastructure. Pipelines also face competition from railroads for the crude oil and natural gas liquids transportation business because building new rail is cheaper, and existing rail beds give more delivery point options than pipelines.

Moreover, not all investments in the pipeline transportation business have been successful. For example, the Rockies Express Pipeline (REX), completed in 2009 at a cost of about $6.2 billion, was built to deliver natural gas from Colorado and Wyoming to demand centers as far east as Ohio.[10] The subsequent development of economically recoverable shale gas reserves in the Marcellus and Utica regions has upended REX’s value proposition such that it has operated at a load factor of only sixty-six percent in 2013.[11] This resulted in bond ratings agencies questioning REX’s ability to maintain earnings after its anchor shippers’ contracts expire in 2019, absent timely action to enter into new contracts.[12] Current anchor shippers vigorously oppose entering into new contracts for shale gas shipments from east to west, making REX’s future prospects uncertain.[13]

Master Limited Partnerships[14] Today and the Master Limited Partnerships Parity Act[15]

Master limited partnerships (MLPs) are publicly traded businesses that are taxed as partnerships.[16] A U.S. business entity that is taxed as a partnership, unlike a corporation, is a “pass-through entity” for federal income tax purposes.[17] This means that the partnership does not pay tax as an entity, but rather each partner is allocated his share of partnership income, gain, deductions, losses, and credits annually and pays tax on his distributable share of partnership income regardless of whether the partnership makes any cash distributions to its partners. As a result, there is only a single level of federal income tax (at the partner level) on the income of a partnership. This is in stark contrast to the two levels of tax imposed on the income of a corporation (for a corporation, the income is taxed when earned by the corporation[18] and then again when it is distributed in the form of a dividend to its shareholders).[19]

In 1987, Congress limited the types of businesses that would be taxed as partnerships if they were “publicly traded” out of concern that the widespread use of publicly traded partnerships would erode the corporate tax base.[20] Partnership status, however, was retained for businesses that had traditionally been conducted in partnership form, such as businesses involved in oil and gas exploration and production.[21]

To qualify for MLP status, a business entity that otherwise would be treated as a partnership for federal income tax purposes and whose interests are “publicly traded” must satisfy a “qualifying income” test, which requires ninety percent or more of the gross income of the partnership to be “qualifying income.”[22] Qualifying income includes: (i) passive income such as interest, dividends, and gains from the disposition of property that generates such passive income; (ii) rents and gains from real property; (iii) income and gains from the exploration, development, mining, production, processing, refining, transportation, or marketing of minerals and natural resources; and (iv) income and gains from transactions in commodities in the case of partnerships that buy and sell such commodities as a principal business activity.[23]

MLPs combine the benefits of public corporations whose interests are readily bought and sold on established securities markets and the tax benefits of partnerships, which are not subject to the federal corporate income tax. Such favorable tax treatment allows MLPs to access capital at a lower cost than business entities taxed as corporations. This makes the MLP structure particularly attractive to the capital-intensive pipeline infrastructure transportation business.

In 2008, Congress expanded the definition of qualifying income to include transportation and storage of certain renewable and alternative fuels, such as ethanol and biodiesel, as well as industrial-source carbon dioxide.[24] Income from alternative or renewable energy generation businesses, however, continues to be excluded from qualifying income status.

Legislation has been introduced in the House of Representatives[25] and in the Senate[26] that would expand the definition of qualifying income to allow alternative or renewable energy projects access to the MLP structure. Under the “Master Limited Partnerships Parity Act,” the definition of qualifying income would be expanded to include income from clean energy resources and infrastructure businesses. Qualifying income would include income from renewable energy projects such as wind power, closed and open loop biomass, geothermal, solar, municipal solid waste, hydropower, marine and hydrokinetic, and fuel cells. The legislation would also expand the definition of qualifying income to include income from certain clean energy technologies, including the production, storage, and transportation of renewable fuels, electricity storage, carbon capture and storage, waste heat power production, and energy-efficient building technology.

Opportunities for Solar Generation: Pipeline Infrastructure Synergies

Passage of the Master Limited Partnerships Parity Act could lead to some interesting opportunities and synergies for solar generation and pipeline infrastructure businesses that could begin to address the economic hurdles to pipeline infrastructure development. The Master Limited Partnerships Parity Act would allow a single MLP to be in the pipeline transportation business and the renewable electric generation business because both businesses would generate “qualifying income” that would allow the entity to benefit from favorable tax treatment as a partnership. The solar generation business would give the pipeline operator an additional revenue source from the sale of power, either through bilateral sales, wholesale sales into power markets, or sales under the Public Utility Regulatory Policies Act (PURPA).[27] In addition, the operational costs of the pipeline business would be reduced. For example, while pipeline compressor stations can vary widely by design, they typically incur fuel costs and often emit greenhouse gases and NOx,which imposes additional construction and maintenance costs due to the equipment necessary to meet local or federal emissions limits.[28] As compressor stations are usually spaced approximately every fifty to one hundred miles along a pipeline route,[29] these costs can be significant on long interstate pipelines. Using electricity from solar assets to power compressor operations offers the opportunity to reduce the overall cost of operating the pipeline. Although solar generation only produces power during the day, electric storage devices would allow such power to be used to serve nighttime compressor operations.

Moreover, pipeline companies have right-of-way and permitting institutional knowledge that is readily transferrable to the siting and permitting of solar generation. In the process of constructing a pipeline, pipeline companies must acquire rights-of-way from local landowners along the entire route of the pipeline, including appurtenant parcels for placement of compressor stations that can reach seventy acres each (including the compressor site and additional acreage for sound buffering).[30] Pipeline companies are also familiar with state and local processes for environmental and similar permits. These areas of institutional knowledge are equally relevant to the solar generating facility siting and permitting process.

Infrastructure development related to the shale boom is a complex problem without a single, simple solution. But within every problem lies opportunity, and the beneficial combination of pipeline and solar infrastructure is one potential opportunity that could start to address the need to incentivize investment in pipeline infrastructure in the current economic climate.

 

Preferred citation: Linda E. Carlisle, Daniel A. Hagan & Jane E. Rueger, Investing in U.S. Pipeline Infrastructure: Could the Proposed Master Limited Partnership Parity Act Spur New Investment?, 4 Harv. Bus. L. Rev. Online 32 (2013), https://www.hblr.org//?p=3645.

* Linda E. Carlisle is a Partner in the Tax Group of White & Case LLP. Daniel A. Hagan is a Partner, and Jane E. Rueger is a Counsel, in the Energy Markets and Regulatory Group of White & Case LLP. All are based in White & Case LLP’s Washington, D.C. office. The opinions expressed are those of the authors and do not necessarily reflect the views of the authors’ law firm or its clients.

[1] Energy Info. Admin., Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States [hereinafter EIA 2013 Assessment], (June 13, 2013), at 11, http://www.eia.gov/analysis/studies/worldshalegas.

[2] See Energy Info. Admin., Energy in Brief: What Is Shale Gas and Why Is It Important?, (Dec. 5, 2012), http://www.eia.gov/energy_in_brief/article/about_shale_gas.cfm?src=home-f2.

[3] EIA 2013 Assessment, supra note 1, at 10.

[4] Energy Info. Admin., Annual Energy Outlook 2013, (Apr. 2013), at 2, http://www.eia.gov/forecasts/aeo/chapter_executive_summary.cfm.

[5] EIA 2013 Assessment, supra note 1, at 10.

[6] Id. at 12.

[7] Id.

[8] Christopher E. Smith, Worldwide Pipeline Construction: Crude, Products Plans Push 2013 Construction Sharply Higher, Oil & Gas J, (Feb. 4, 2013), http://www.ogj.com/articles/print/volume-111/issue-02/special-report–worldwide-pipeline-construction/worldwide-pipeline-construction-crude-products.html.

[9] Bill Faries & Mike Lee, Spectra Wins $3 Billion Interstate Florida Gas Pipeline, Bloomberg News, (July 26, 2013), http://www.bloomberg.com/news/2013-07-26/spectra-wins-3-billion-interstate-florida-gas-pipeline.html.

[10] Kinder Morgan Energy Partners, Current Report (Form 8-K, Ex. 99.1) at 128 (June 12, 2009).

[11] Peter Behr, Rockies Express shippers fight a proposed change in gas flows, EnergyWire, (July 26, 2013), http://www.eenews.net/stories/1059985120. Load factor refers to customers’ actual utilization of a pipeline’s capacity compared to its maximum capacity.

[12] Id.

[13] See id.

[14] For federal tax purposes, master limited partnerships include both limited partnerships and limited liability companies.

[15] S. 795, 113th Cong. (2013); H.R. 1696, 113th Cong. (2013).

[16] See I.R.C. § 7704(c)(1) (2012).

[17] See id. § 701.

[18] See id. § 11.

[19] See id. § 61(a)(7).

[20] H.R. Rep. No. 100-391, pt. 2, at 1064 (1987), reprinted in 1987 U.S.C.C.A.N. 2313-378, 2313-680.

[21] Id. at 2313-683.

[22] I.R.C. § 7704(c)(2) (2012).

[23] See id. § 7704(d).

[24] See id. § 7704(d)(1)(e).

[25] H.R. 1696, 113th Cong. (2013).

[26] S. 795, 113th Cong. (2013).

[27] PURPA was enacted in 1978 with the intent to spur development of more efficient and renewable generating facilities developed and owned by entities independent from incumbent franchised utilities. See Fed. Energy Regulatory Comm’n, What is a Qualifying Facility? http://www.ferc.gov/industries/electric/gen-info/qual-fac/what-is.asp (last visited Nov. 23, 2013). To that end, PURPA established a new class of generating facilities called qualifying facilities that receive special rate and regulatory treatment. See id. One type of qualifying facility, the small power production facility (SPP QF), is a generating facility of eighty-megawatts or less that uses, as a primary energy source, renewable (hydro, wind, or solar), biomass, waste, or geothermal resources. See id. Facilities that meet the size and fuel requirements to be SPP QFs and file a simple self-certification form with the Federal Energy Regulation Commission enjoy numerous rate and regulatory benefits. See Fed. Energy Regulatory Comm’n, What Are the Benefits of QF Status?

http://www ferc.gov/industries/electric/gen-info/qual-fac/benefits.asp (last visited Nov. 23, 2013).

[28] Ranier Kurz et al., Gas Compressor Station Economic Optimization, Int’l J. of Rotating Machinery, Vol. 2012, available at http://www.hindawi.com/journals/ijrm/2012/715017/.

[29] Energy Info. Admin., Natural Gas Compressor Stations on the Interstate Pipeline Network: Developments Since 1996 (Nov. 2007),

http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngcompressor/ngcompressor.pdf.

[30] See, e.g., 240 No. 7 Pipeline & Gas J., Millennium Touts Completion of Minisink Compressor Station, (July 2013), http://www.pipelineandgasjournal.com/millennium-touts-completion-minisink-compressor-station.

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Why Are Foreign Investments in Domestic Energy Projects Now Under CFIUS Scrutiny?

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Stephen Heifetz and Michael Gershberg*

Until recently, the Committee on Foreign Investment in the United States (CFIUS or the Committee) rarely affected domestic energy projects. That has changed, and CFIUS now actively reviews and sometimes alters transactions that result in foreign control of U.S. energy companies. In just the past several months, CFIUS has blocked an acquisition of Oregon wind farm projects (the Ralls/Terna case),[1] reportedly imposed conditions on the acquisition of a large oil and gas company (the CNOOC/Nexen case),[2] and approved an acquisition of a high-tech battery manufacturer only after the deal was restructured to carve out its government contracting business (the Wanxiang/A123 case).[3]

There are three primary drivers behind this recent scrutiny. The first is the rise of China—on the one hand as a trading and investment partner, and on the other hand, as a perceived security threat. Each of the three CFIUS cases referenced above concerned Chinese investments in domestic energy projects.[4] The second driver is U.S. government concern about the vulnerability of U.S. infrastructure, particularly to a cyber attack on U.S. networked systems, such as energy grids and other energy-related assets. The third driver is a change in the balance among the agencies that comprise CFIUS. In particular, the Department of Defense has sought aggressively to use the Committee’s authority to keep potential foreign adversaries far away from U.S. security facilities, while the more trade-oriented agencies have been weakened in CFIUS deliberations.[5]

CFIUS Background

CFIUS is an interagency committee chaired by the Department of Treasury.[6] Its mandate is to review foreign investments in U.S. businesses to ensure that such investments do not adversely affect national security.[7] More specifically, CFIUS reviews transactions that result in foreign “control” of U.S. businesses where that foreign control may affect national security.[8]

Though the Committee often reviews more than one hundred cases per year,[9] it typically sees potential security implications in only a dozen or so.[10] In those cases, CFIUS generally protects against possible adverse effects by obtaining commitments from the foreign investor. These commitments, which take the form of a “risk mitigation agreement,” may include such requirements as the use of specified vetting procedures for key employees or restrictions on foreign access to sensitive technology or facilities.[11] When CFIUS cannot mitigate the risk presented by a transaction through an agreement, its recourse is to recommend that the President block the transaction.[12] The President is authorized to “take such action for such time as the President considers appropriate to suspend or prohibit any covered transaction that threatens to impair the national security of the United States.”[13] CFIUS recommendations to the President are very rare, usually no more than one or two per year.[14] In those rare cases, if the parties do not voluntarily withdraw the transaction, the President is likely to follow the Committee’s recommendations to preclude foreign control of the U.S. business. Transacting parties have forced a Presidential decision only twice in the Committee’s history, and in both cases the President exercised his authority to block the transaction.[15]

However, there is a significant benefit to undergoing CFIUS review from the perspective of the transacting parties. If CFIUS approves the deal, as it does in the vast majority of cases, then the deal is insulated from executive branch interference on national security grounds.[16]

The CFIUS process is nominally voluntary. There is no requirement that parties conducting transactions involving foreign entities notify CFIUS, even when those transactions result in foreign control or clearly involve assets relevant to national security.[17] However, the Committee monitors a wide range of transactions, primarily through open media sources. If a “non-notified transaction” is of interest to CFIUS, the Committee will offer the parties the opportunity to submit a notification.[18] In the event that transacting parties ignore the “voluntary” submission request, CFIUS has authority to initiate a review of a transaction on its own.[19] A notice filed by the parties will invariably put the transaction in a better light than if the parties refuse to submit a notice and the Committee undertakes a review on its own accord.

The Committee’s attention to non-notified transactions, which has grown over the last few years, incentivizes transacting parties to err on the side of voluntarily notifying CFIUS for several reasons. First, when CFIUS requests a notification in the absence of a voluntary notice, the parties begin the CFIUS process with an air of distrust. These transactions receive additional scrutiny—both because CFIUS already has decided that the transaction may raise national security concerns and because CFIUS generally is suspicious that the parties deliberately sought to avoid review. Second, because CFIUS generally requests notice only after the transaction has closed, there is greater commercial risk if CIFIUS rejects the deal or if it imposes burdensome conditions. There is no opportunity in such cases for the parties to restructure the transaction in a way that helps address the Committee’s concerns. Third, there is greater risk that CFIUS will reject a non-notified transaction or impose very burdensome conditions, because CFIUS often finds it more difficult to mitigate national security risks after a transaction has closed.

The current state of affairs with regard to CFIUS regulation can be summarized as follows: CFIUS has significant power over foreign investments in U.S. companies, and provides strong incentives for transacting parties to voluntarily submit to a review. Considering this background, we can identify several factors that have driven recent Committee attention to domestic energy projects.[20]

The Rise of China

China’s emergence as a world power has been accompanied by concerns about Chinese espionage directed at the United States. For example, an October 2012 report by the U.S. House Permanent Select Committee on Intelligence alleged that investments by Chinese telecommunications equipment companies Huawei and ZTE presented significant national security risks.[21] A February 2013 report by the security company Mandiant Corporation alleged that the Chinese government sponsored cyber espionage.[22] In March 2013, the U.S. National Security Advisor alleged that Chinese entities are the sources of “sophisticated, targeted theft of confidential business information and proprietary technologies through cyber intrusions emanating from China on an unprecedented scale.”[23] In addition, the U.S. Government has recently accused the Chinese military of launching cyber attacks against U.S. government and private networks.[24]

At the same time, the flow of Chinese direct investment into the U.S.—one indicator of the U.S.-China economic relationship—has been growing rapidly, from $129 million in 2006, to $1.9 billion in 2009, to $6.5 billion in 2012.[25] This trend has resulted in more instances of Chinese investment in U.S. energy projects and companies. With China joining the United States as the world’s biggest consumers of energy,[26] the development of energy projects should be an arena for extensive investment and collaboration between the two world powers. In fact, in President Obama’s first year in office, the Administration announced multiple cooperative energy development measures with China and there have been regular follow-on efforts.[27]

Yet extensive collaboration also can give rise to conflict, leading the U.S. to view China as a strategic threat as well as a partner. This threat has led CFIUS to closely examine recent Chinese investment in U.S. energy projects. Such transactions present concerns such as U.S. energy security, China’s ability to infiltrate U.S. power systems, the transfer of key technology to China, and the proximity of foreign-controlled projects to sensitive military facilities.

Infrastructure Vulnerability

In recent years, the energy sector has become a focus of national security concerns, along with traditional security-related areas such as defense, telecommunications, and high technology. As the power grid is increasingly reliant on electronic systems, energy projects are now a main point of vulnerability to the United States. Other energy projects may present national security implications for reasons of energy independence or the valuable technology involved. Accordingly, the 2007 amendments to the CFIUS statute stressed the importance of the energy sector.[28] Among the list of factors CFIUS must consider in its proceedings are “the potential national security-related effects on United States critical infrastructure, including major energy assets,” and “the long-term projection of United States requirements for sources of energy and other critical resources and material.”[29]

The CFIUS cases referenced at the outset of this article—Ralls/Terna, CNOOC/Nexen, and Wanxiang/A123—all involved Chinese investments in energy companies that, from the perspective of CFIUS, represented potential national security vulnerabilities.[30] The acquisition by Chinese-owned Ralls Corp. of assets from Greek-owned Terna concerned wind farm projects that would connect to a regional electric grid and that were near a Department of Defense flight facility.[31] The CNOOC acquisition of Canadian energy company Nexen involved oil platforms in the Gulf of Mexico that the Department of Defense viewed as strategic locations.[32] Wanxiang’s purchase of A123, a high-tech battery manufacturer, stalled until the parties decided that Wanxiang would not acquire A123’s defense-related business.[33]

In other words, CFIUS viewed many of the assets at issue as potentially exploitable to the detriment of U.S. security. Coupled with U.S. concern about China as an espionage threat and source of cyber attacks, each case presented a combustible mixture. Fortunately, CFIUS ultimately approved the CNOOC/Nexen and Wanxiang/A123 cases in early 2013.[34] However, in both cases the parties reportedly had to undertake substantial commitments to ensure CFIUS approval. In CNOOC/Nexen, CNOOC apparently was obligated to agree to a broad range of security measures concerning Nexen’s oil platform assets in the Gulf of Mexico.[35] In Wanxiang/A123, Wanxiang agreed to carve out pieces of A123’s business that were of importance to the U.S. government.[36] On the other hand, the President blocked the Ralls/Terna deal in September 2012 because, due to the proximity to U.S. defense facilities, the President found that the Chinese owners “might take action that threatens to impair the national security of the United States.”[37]

Changing Balance Within CFIUS

CFIUS decisions ultimately are made by individual representatives from the separate agencies that comprise the Committee. These individuals—bright, dedicated, and committed to the national interest—discuss each CFIUS case among themselves.[38] They gather in person at least once each week and continue their dialog through emails and by phone. These individuals each bring to bear their own experiences, knowledge, and interests. They also are obligated to represent the views of their agencies, and act consistently with their agencies’ missions, while serving on CFIUS.[39]

For example, a cyber attack that shuts down a city’s power would concern personnel at the Department of Homeland Security more than personnel at the Office of the United States Trade Representative (USTR). Conversely, if the United States enters into a counterproductive trade dispute, it would directly affect personnel at USTR much more than at the Department of Homeland Security. In addition, the relevant personnel are held accountable by pressure and potential fallout—from inside their agencies, Congress, and the press—if their areas of expertise lead to a compromise of national security. That is not to say that concerns are strictly limited in this way, but it is a rough approximation of how representatives from each of the agencies behave. An additional layer of complexity results from the varied views on an issue shaped by Committee members’ personal experience and the agency positions for which they advocate.

Accordingly, representatives from the more security-focused agencies—the Departments of Homeland Security, Justice, and Defense—typically are more hawkish in Committee deliberations than are representatives from other agencies. On the other hand, representatives from the Departments of State and Commerce and USTR are often focused on commercial, trade, and diplomatic interests. In the past, this latter group generally defended these interests strongly. In CFIUS deliberations they argued in favor of approving deals that the hawkish agencies sought to scuttle or burden with conditions. In their view, the trade or diplomatic benefits of international commercial transactions and an open investment environment outweighed many concerns raised by the security agencies.

Recently, however, the trade-oriented agencies have been more muted in CFIUS deliberations. This change may be a function of the particular individuals involved in the deliberations (since the cast of individuals changes over time), or a function of policy concerns at their agencies. The State Department, for example, recently has been playing a critical role on U.S. policy vis-à-vis Iran. That may make some bureaucracies within the State Department more hawkish, which may in turn create different incentives for the State Department’s CFIUS representatives. By many accounts, the representatives from the trade-oriented agencies recently appear less inclined to challenge their security-focused counterparts.

The Department of Energy plays a unique role in CFIUS because it has an interest in security, trade, and the promotion of renewable energy. Yet in recent cases involving Chinese investments in U.S. energy projects—where the Department of Energy could potentially play a leading role—its trade and environmental interests were insufficient for it actively to challenge the security-focused agencies.

At the same time, the Department of Defense, in particular, has leveraged CFIUS authority as a way to keep potential foreign adversaries away from U.S. government security facilities.[40] Defense representatives on the Committee have argued aggressively that any advantage that a potential foreign adversary might gain from U.S. investment—for example, by acquiring a company with access to an important network that could be used for a cyber attack—must be nullified. The result is occasionally the scuttling of the deal entirely, either voluntarily by the parties or by Presidential order as in the Ralls/Terna case.[41]

Conclusion

With counter-arguments from trade-oriented agencies now muted or absent, the hawkish agencies are determining CFIUS outcomes in cases where there are security concerns. The rise of China has brought increased Chinese investment in the United States, including energy-related investments. With this investment, however, have come security concerns, particularly regarding Chinese espionage. Coupled with concerns about infrastructure vulnerability, these dynamics have given rise to an increased number of difficult CFIUS cases that have involved domestic energy projects.

 

Preferred citation: Stephen Heifetz & Michael Gershberg, Why Are Foreign Investments in Domestic Energy Projects Now Under CFIUS Scrutiny?, 3 Harv. Bus. L. Rev. Online 203 (2013), https://www.hblr.org//?p=3356.

* Stephen Heifetz and Michael Gershberg are members of Steptoe & Johnson LLP’s International Regulation and Compliance Practice in Washington, D.C. Mr. Heifetz represented the Department of Homeland Security on CFIUS from 2006–10. This Article draws from the authors’ personal experience with CFIUS.

[1] See Regarding the Acquisition of Four U.S. Wind Farm Project Companies by Ralls Corporation, 77 Fed. Reg. 60,281 (Oct. 3, 2012).

[2] Roberta Rampton & Scott Haggett, CNOOC-Nexen Deal Wins U.S. Approval, Its Last Hurdle, Reuters, Feb. 12, 2013, available at http://www.reuters.com/article/2013/02/12/us-nexen-cnooc-idUSBRE91B0SU20130212. CFIUS proceedings are related documents are kept strictly confidential pursuant to statutory requirement. See 50 U.S.C. app. § 2170(c) (2012). Therefore, with few exceptions, there is no official public information on the results of CFIUS proceedings. However, details of newsworthy cases are often reported in the press.

[3] Michael Bathon, Wanxiang Wins U.S. Approval to Buy Battery Maker A123, Bloomberg (Jan. 30, 2013), http://www.bloomberg.com/news/2013-01-29/wanxiang-wins-cfius-approval-to-buy-bankrupt-battery-maker-a123.html.

[4] See Andrew Zajac, Ralls Sues to Void U.S. Wind-Farm Purchase Obama Blocked, Bloomberg (Jan. 29, 2013), http://www.bloomberg.com/news/2013-01-29/ralls-sues-to-void-u-s-wind-farm-purchase-obama-blocked.html; Rampton & Haggett, supra note 2; Bathon, supra note 3.

[5] The authors’ discussion of the Committee’s changing balance draws from personal experience.

[6] See 50 U.S.C. app. § 2170(k). The agencies statutorily charged with CFIUS obligations are the Departments of Treasury, Homeland Security, Commerce, Defense, State, Justice, Energy, Labor (as a non-voting member), and the Office of the Director of National Intelligence (also a non-voting member). Id. In addition, by executive order, the Office of the United States Trade Representative (USTR) and the Office of Science and Technology Policy both regularly participate in the Committee. See Exec. Order No. 13,456 § 3(b), 73 Fed. Reg. 4677, 4677 (Jan. 23, 2008).

[7] See 50 U.S.C. app. § 2170(k).

[8] CFIUS regulations define “control” of a U.S. business quite loosely—virtually any foreign ability to cause a company to act (or not to act) in a particular manner constitutes foreign control. See 31 C.F.R. § 800.204 (2012). However, at least “control” is defined. Whether a transaction may affect national security, though subject to a statutory “factors test,” is virtually indefinable. See 50 U.S.C. app. § 2170(f). The amorphous quality of the national security inquiry is underscored by the last statutory factor: “such other factors as the President or the Committee may determine to be appropriate.” Id. § 2170(f)(11).

[9] See Comm. on Foreign Inv. in the U.S., Annual Report to Congress CY 2011 2 (Dec. 2012), http://www.treasury.gov/resource-center/international/foreign-investment/Documents/2012%20CFIUS%20Annual%20Report%20PUBLIC.pdf.

[10] See id. at 18 (“From 2009 through 2011, 22 cases (eight percent) resulted in the use of legally binding mitigation measures.”).

[11] These commitments are embodied in risk mitigation agreements between the government and the acquiring parties. See 50 U.S.C. app. § 2170(l)(1) (authorizing mitigation agreements).

[12] See Exec. Order No. 13,456 § 6(c), 73 Fed. Reg. 4677, 4678–79 (Jan. 23, 2008).

[13] 50 U.S.C. app. § 2170(d)(1).

[14] See generally Comm. on Foreign Inv. in the U.S., supra note 9, at 3 (indicating that “there were no transactions that resulted in a Presidential decision”).

[15] In October 2012, the President blocked Ralls’ acquisition of Oregon wind farm projects. See Regarding the Acquisition of Four U.S. Wind Farm Project Companies by Ralls Corporation, 77 Fed. Reg. 60,281 (Oct. 3, 2012). In February 1990, the President blocked China National Aero-Technology Import and Export Corporation’s acquisition of aircraft parts manufacturer MAMCO Manufacturing, Inc. See Order Pursuant to Section 721 of the Defense Production Act of 1950, 55 Fed. Reg. 3935 (Feb. 6, 1990).

[16] See 50 U.S.C. app. § 2170(b)(1)(D). See also Edward M. Graham & David M. Marchick, U.S. National Security and Foreign Direct Investment 33–58 (2006).

[17] A “notice” to CFIUS initiates the CFIUS review process. See 31 C.F.R. § 800.401 (2012). Notices are virtually always submitted jointly by the parties to the transaction that is subject to CFIUS review because the regulations require submission of information related to both parties.

[18] Id. § 800.401(b).

[19] Id. § 800.401(c).

[20] While the Committee’s attention to domestic energy projects has been limited until recently, one notable exception was the Chinese National Offshore Oil Corporation’s (CNOOC) proposed acquisition of Unocal Oil Company in 2005. See Francesco Guerrera, CNOOC at Odds with Congress over Unocal Deal, Fin. Times (July 26, 2005), http://www.ft.com/intl/cms/s/0/07ca91da-fdfc-11d9-a289-00000e2511c8.html. CNOOC withdrew its bid for Unocal, as well as its CFIUS notice, amid U.S. political pressure. See Ben White, Chinese Drop Bid To Buy U.S. Oil Firm, Wash. Post (Aug. 3, 2005), http://www.washingtonpost.com/wp-dyn/content/article/2005/08/02/AR2005080200404.html. The House of Representatives enacted a non-binding resolution opposing the transaction and stating that CNOOC’s planned acquisition of Unocal “would threaten to impair the national security of the United States.” See H.R. Res. 344, 109th Cong. (2005). A bill was introduced in the Senate to prohibit the sale and the House passed an amendment to an appropriations bill that would have prohibited CFIUS from approving the deal. See S. Res. 1412, 109th Cong. (2005); H.R. Res. 3058, 109th Cong. (2005).

[21] See U.S. House of Representatives Permanent Select Comm. on Intelligence, 112th Cong., Investigative Report on the U.S. National Security Issues Posed by Chinese Telecommunications Companies Huawei and ZTE 44–46 (Oct. 8, 2012), available at http://intelligence.house.gov/sites/intelligence.house.gov/files/documents/Huawei-ZTE%20Investigative%20Report%20%28FINAL%29.pdf.

[22] Mandiant, APT1: Exposing One of China’s Cyber Espionage Units (Feb. 2013), http://intelreport.mandiant.com/Mandiant_APT1_Report.pdf.

[23] Thomas Donilon, Nat’l Sec. Advisor to President Obama, The United States and the Asia-Pacific in 2013 (Mar. 11, 2013) (transcript available at http://asiasociety.org/new-york/complete-transcript-thomas-donilon-asia-society-new-york).

[24] David E. Sanger, U.S. Blames China’s Military Directly for Cyberattacks, N.Y. Times (May 6, 2013) http://www.nytimes.com/2013/05/07/world/asia/us-accuses-chinas-military-in-cyberattacks.html?pagewanted=all&_r=0 (citing U.S. Department of Defense report on Military and Security Developments Involving the People’s Republic of China).

[25] See Chinese Investment Monitor, Rhodium Group, http://rhg.com/interactive/china-investment-monitor (last visited Apr. 20, 2013).

[26] Spencer Swartz & Shai Oster, China Tops U.S. in Energy Use, Wall St. J. (July 18, 2010), http://online.wsj.com/article/SB10001424052748703720504575376712353150310.html.

[27] See, e.g., U.S. Dep’t of Energy, U.S.-China Clean Energy Cooperation (Jan. 2011), available at http://energy.gov/sites/prod/files/USChinaCleanEnergy_0.PDF.

[28] Foreign Investment and National Security Act of 2007, Pub. L. No. 110-49, 121 Stat. 246 (2007).

[29] Id. § 4.

[30] See Zajac, supra note 4; Rampton & Haggett, supra note 2; Bathon, supra note 3.

[31] See Helene Cooper, Obama Orders Chinese Company to End Investment at Sites Near Drone Base, N.Y. Times, Sept. 29, 2012, at A16, available at http://www.nytimes.com/2012/09/29/us/politics/chinese-company-ordered-to-give-up-stake-in-wind-farms-near-navy-base.html.

[32] See Sara Forden & Rebecca Penty, Nexen Rigs Near U.S. Military Base May be Issue in CNOOC Review, Fin. Post (Dec. 12, 2006), http://business.financialpost.com/2012/12/06/nexen-rigs-near-u-s-military-base-may-be-issue-in-cnooc-review/?__lsa=a706-0039.

[33] Erin Ailworth, A123 Deal Hangs on Secretive Federal Panel, Bos. Globe (Jan. 9, 2013), http://www.bostonglobe.com/business/2013/01/09/deal-hangs-secretive-federal-panel/92R7hEpT6Jrgdsod9txw8M/story.html.

[34] See Rampton & Haggett, supra note 2; Bathon, supra note 3.

[35] See Rebecca Penty & Sara Forden, CNOOC Said to Cede Control of Nexen’s U.S. Gulf Assets, Bloomberg (Mar. 1, 2013), http://www.bloomberg.com/news/2013-03-01/cnooc-said-to-cede-control-of-nexen-s-u-s-gulf-assets.html.

[36] See Bathon, supra note 3.

[37] Regarding the Acquisition of Four U.S. Wind Farm Project Companies by Ralls Corporation, 77 Fed. Reg. 60,281, 60,281 (Oct. 3, 2012).

[38] The authors’ discussion of the Committee’s changing balance draws from practical experience.

[39] While the day-to-day CFIUS participants represent the views of their agencies, certain actions require the approval of high-level political appointees. See 50 U.S.C. app. § 2170(b)(1)(F), (b)(2)(D)(ii), (b)(3)(C)(iv)(II).

[40] See, e.g., Memorandum from Davis Graham & Stubbs LLP & Reed Smith LLP to Nw. Non-Ferrous Int’l Co. & Firstgold Corp. (Dec. 14, 2009), available at http://graphics8.nytimes.com/packages/images/nytint/docs/memo-regarding-the-sale-of-firstgold-corp/original.pdf.

[41] Regarding the Acquisition of Four U.S. Wind Farm Project Companies by Ralls Corporation, 77 Fed. Reg. at 60,281.

By

Unreasonable Delays: CFIUS Reviews of Energy Transactions

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Joshua C. Zive*

I.               Introduction

The role of foreign investment in the U.S. energy sector has changed significantly in recent years. The development of domestic oil and gas resources has resulted in a significant increase in foreign interest in the U.S. as a target for investment in the wide range of industries connected to domestic oil and gas production, transportation, and use.[1] Such investment is important to the continued growth and success of the U.S. energy sector and, in order to facilitate these ventures, the regulatory process surrounding energy transaction investment should not impose unreasonable delays. Unfortunately, delays and burdens associated with the Committee on Foreign Investment in the Unites States (CFIUS) are playing an increasingly significant and frustrating role in energy transactions.

This Article is not intended to discuss the wide range of substantive issues involved in a CFIUS review of energy transactions, but instead to call attention to timing concerns that have received little attention. As a result of legal and regulatory changes, CFIUS reviews of energy transactions are confronting lengthy delays that introduce needless uncertainty and costs into the investment climate. These delays frustrate the intended role of CFIUS review and make it unnecessarily difficult for energy transactions to be designed and executed in an efficient manner.

II.             Living in the Now: CFIUS after FINSA

The U.S. has long struggled with efforts to balance concerns about the national security implications of foreign investment with the economic benefits of encouraging foreign investment in the U.S. CFIUS, an interagency committee chaired by the Department of the Treasury and charged with reviewing foreign acquisitions of U.S. businesses, was created as the tool to help find this balance.[2] CFIUS was created by Executive Order in 1975 and given limited jurisdiction and power to review foreign investment in the U.S., although CFIUS jurisdiction and powers were expanded in 1988 when Congress adopted the Exon-Florio amendment to section 721 of the Defense Production Act.[3] Since 1988, CFIUS has had significant discretion to review foreign investment in the U.S. with almost complete confidentiality and protection from judicial review, providing the public and the investing community with virtually no precedent that can be used to predict CFIUS behavior.[4]

Although the Exon-Florio regime provided CFIUS with broad powers, its process has had a rather narrow substantive scope. These limits resulted from a desire to prevent CFIUS from unduly interfering with foreign investment, and regulations at the time focused on transactions involving “products, services, and technologies that are important to U.S. national defense requirements.”[5]

In addition to having a narrow scope, the review process under Exon-Florio was fairly simple and predictable. Parties would file a notice voluntarily (or CFIUS would require that a notice be filed), and CFIUS would conduct an initial review within 30 days.[6] If CFIUS identified a need for further investigation, the committee could use an additional 45 days to conduct an investigation, and ultimately conclude the investigation with a recommendation for Presidential action.[7] This recommendation was required to be taken or rejected within 15 days of being sent to the President.[8] The CFIUS regulations establishing this process were vague in many respects, but in practice parties to most energy transactions that were unrelated to defense could plan around the CFIUS process knowing that benign transactions would generally be cleared by CFIUS after the initial 30-day review, which began when the parties submitted a formal voluntary notice.[9]

However, for companies involved in the energy sector, CFIUS procedure was fundamentally changed by the controversy surrounding the acquisition of the port management business of Peninsular and Oriental Steam Navigation Company (P&O) by Dubai Ports World (DP World), an entity ultimately owned by the government of the United Arab Emirates.[10] DP World’s acquisition of P&O included a transfer of leases for management of six major U.S. ports.[11] Although CFIUS cleared the DP World transaction, it sparked significant controversy and scrutiny of the CFIUS process that ultimately resulted in DP World selling all of the assets in question to U.S. entities in order to defuse the controversy.[12] In the wake of the DP World transaction, the legal foundation for CFIUS reviews of foreign investment in the U.S. was overhauled by the enactment of the Foreign Investment and National Security Act of 2007 (FINSA) [13] and the promulgation of new regulations by CFIUS in 2008.[14]

FINSA and subsequent regulations made a variety of significant changes to the nature and process of CFIUS review. This Article will discuss the following aspects of the CFIUS review process:

  • Broadening the definition of national security to explicitly include “issues relating to ‘homeland security’, including its application to critical infrastructure” and noting that this review includes “major energy assets.”[15]
  • Creating a three-tiered pre-notice, review, and investigation process that includes an initial pre-notice submission, a 30-day review of a formal notice (either filed voluntarily by parties or required to be filed by CFIUS), followed by a 45-day investigation if certain conditions are met.[16]
  • The creation of a presumption that foreign acquisitions involving critical infrastructure and acquisitions by government-owned investors require a 45-day investigation phase, unless senior CFIUS officials sign off that no investigation is needed.[17]

III.  New Delays: International Energy Transactions Under FINSA

A.   The Unlimited Definition of Critical Infrastructure

Prior to FINSA, determining whether a transaction fell under CFIUS jurisdiction was a simpler task for energy transactions. If the transaction resulted in a foreign-owned or controlled entity obtaining control over an existing U.S. business, and that business was involved with products or services that had a particular relationship to national security, such as materials essential to national defense, then submission to CFIUS review was prudent. CFIUS would review the notice submitted by the parties to the transaction and, if national security issues were identified, a 45-day review could be added to the initial 30-day review period. In the context of most energy transactions, those not involving energy assets connected to the U.S. military or occupying a dominant market share position in a particular energy sector, it was normal to abstain from submitting a transaction for CFIUS review because no national security issues could be identified, and those transactions that were submitted for review were often cleared by CFIUS within the first 30-day review period. The confidentiality of the CIFUS process has made reliable data difficult to obtain, but in 2006 the Congressional Research Service (relying on research conducted by outside sources) reported that CFIUS reviewed approximately 1,500 transactions from 1988 until 2005, with only twenty-five of those transactions being subjected to a full investigation.[18]

Determining how an energy-related notice will be treated by CFIUS is a more complex endeavor now because of FINSA’s treatment of “critical infrastructure.”[19] Critical infrastructure is defined as “systems and assets . . . so vital to the United States that the incapacity or destruction of such systems or assets would have a debilitating impact on national security.”[20] This term is important because FINSA added a new provision to the law requiring that CFIUS take into account “the potential national security-related effects on United States critical infrastructure, including major energy assets” when conducting a review of a transaction.[21]

While it is clear that these changes expand the scope of CFIUS review, it is less clear where that expansion ends. In particular, questions remain as to what sorts of infrastructure are included in the critical infrastructure category, other than “major energy assets,” and what exactly makes an energy asset “major.”[22] These questions remain unanswered, as CFIUS has refused to provide examples of infrastructure that might be considered critical infrastructure in their regulations.[23]

The FINSA language governing critical infrastructure has left the energy sector in the unfortunate position of being the only industry sector mentioned specifically as an example of critical infrastructure, with no indication of the types of energy assets that are considered neither major nor critical.[24] This direct reference to the energy sector is important because, in the author’s experience, spotlighting energy assets has both compelled more parties involved in international energy transactions to file CFIUS notices in order to contain the risk of subsequent CFIUS review of those transactions and has resulted in those notices facing longer delays as a result of the FINSA provisions discussed below.

B.   The New “Pre-Notice” Notice

During the Exon-Florio era of CFIUS, parties could prepare a voluntary notice pursuant to CFIUS regulations and, as long as that notice included all of the information listed in the regulations, the 30-day review period would begin upon filing notice.[25] However, that process has changed substantially in the wake of FINSA.

Although FINSA made no mention of any pre-notice consultations, CFIUS promulgated regulations in which pre-notice consultations assumed a new and formal role in the CFIUS process. The language included in the post-FINSA CFIUS regulations provides that parties to transactions are “encouraged to consult” with CFIUS in advance of filing a notice and to file a draft notice in “appropriate cases.”[26] The regulatory language further states that all pre-notice materials must be provided to CFIUS “at least five business days before the filing of a voluntary notice.”[27]

The pre-notice process has been described by CFIUS as a tool to help CFIUS “understand the transaction and to suggest information that the parties may wish to include in their notice to assist [CFIUS] in addressing any national security considerations as efficiently as possible.”[28] While this objective seems reasonable, in practice the pre-notice period has become a functionally mandatory process that introduces new and unpredictable delays into the CFIUS review process. Although the CFIUS regulations indicate that a draft notice should be filed when appropriate, the reality is that CFIUS expects a draft notice in all cases. Once CFIUS receives the draft notice, CFIUS will often call for explanations or information beyond that required by regulations,[29] and it has become common practice for CFIUS to require early submission of the Personal Identifier Information (PII).[30] CFIUS has made it clear to filers that notices found to be insufficiently clear or complete will be rejected[31], and in practice this has meant that only after CFIUS deems a pre-notice sufficiently clear and complete will CFIUS recommend that a formal voluntary notice be filed. If parties were to act without such a recommendation, they risk having the formal notice rejected by CFIUS as incomplete, meaning that the formal review process would never begin.[32]

The creation of a technically voluntary, but functionally mandatory, pre-notice process has added a significant amount of time to the CFIUS approval process, particularly for complex energy transactions. Not accounting for the time required to prepare the initial draft notice, the pre-notice consultation process can often drag on for weeks as parties scramble to collect all the individual bits of data requested by CFIUS. For complex energy transactions that involve multiple international parties, a variety of subsidiaries, and complex, geographically dispersed assets, the pre-notice process often involves scores of request and fact-finding missions at the behest of CFIUS. During this entire period, there is no clock running on the CFIUS pre-notice process and the formal review clock is not yet started. For energy transactions that operate under tight timelines as a result of tax periods or other exogenous factors, these weeks can sometimes make the difference between a transaction being viable or not.

C.   Mandatory 45-day Investigation for Critical Infrastructure

The virtually unlimited definition of critical infrastructure may capture any substantial energy asset, and it creates an additional layer of delays during CFIUS reviews of energy transactions in the post-FINSA world.[33]

The normal period of review for a non-controversial transaction prior to the adoption of FINSA was 30 days.[34] By regulation, a CFIUS review only moves to an additional 45-day investigation if CFIUS finds that national security risks necessitate the additional investigation.[35] However, FINSA altered those procedures because Congress included a requirement in FINSA that a 45-day investigation be conducted for any transaction that “would result in control of any critical infrastructure of or within the United States by or on behalf of any foreign person” if that transaction could “impair national security.”[36]

This aspect of CFIUS has had direct consequences on the timing of CFIUS reviews of energy transactions. As discussed, under the broad and ambiguous definition in FINSA, which CFIUS has declined to narrow, virtually any energy-related asset can be considered critical infrastructure, the destruction of which could arguably impair national security in some manner, however small.[37] Accordingly, CFIUS is able to use this provision to justify adding an additional 45 days to the review of practically any notice concerning energy assets, meaning that the formal review period is actually a minimum of 75 days for most energy related transactions. As such, the notion that CFIUS is bound to a 30-day review period is simply not the case for most energy transactions.

IV.          Conclusions

Although the energy sector was not the focus of the DP World controversy or FINSA, many benign energy transactions are confronting the type of CFIUS delays that one would expect to be associated only with uniquely sensitive assets such as cutting-edge technology or defense equipment. Changes in timing and cost expectations can often make the difference between success or failure in complex international energy deals and, even under the best of conditions, negotiating and closing energy transactions is a difficult and time-consuming endeavor. While the role of foreign investment in the U.S. energy sector is increasingly important, the changes FINSA made to the CFIUS process have introduced delays and unnecessary uncertainty for foreign investors and U.S. energy companies.

While every transaction poses unique substantive and analytical issues related to CFIUS, there are common problems faced by most international energy transactions that trigger CFIUS jurisdiction. As a result of the breadth of the term “critical infrastructure,” the creation of a new pre-notice mandate, and the statutory imposition of an additional 45-day investigation period for transactions involving critical infrastructure, many parties must simultaneously struggle to escape CFIUS review and plan for a review period that has become as long 90 days when the pre-notice period is included. Given that the ability to provide details necessary for a formal notice means parties cannot file until they have agreed to the details of a transaction,[38] and that CFIUS informs counsel that they prefer that notice is filed prior to closing,[39] many energy transactions are required to wait in limbo for up to three months pending CFIUS review.[40]

The unnecessary delays faced by energy transactions can discourage important foreign investment and create unexpected problems that result in aborted transactions as result of events that occur during the long CFIUS review period. As such, there is risk going forward that an increasing number of parties might consider choosing to avoid these delays by not filing a voluntary notice, which leaves a lingering risk of a transaction being reviewed and potentially unwound by CFIUS after it has closed.

Decisions regarding whether to file a voluntary notice with CFIUS should be motivated by reasonable evaluations of national security issues and risks and not by the costs associated with delays. If parties choose not to file notices due to concerns about delays, it is likely that some transactions that may raise real or perceived national security issues will be not be reviewed by CFIUS before closing. When the media later reports on either the actual or alleged risks of these transactions, the risk of more controversies like DP World becomes more pronounced. Such controversies undermine the confidence that foreign investors have in the U.S., harming the economy and the energy sector. Furthermore, it is possible that some of the transactions that seek to avoid CFIUS review, in order to avoid delays, may pose actual national security risks if those transactions result in substantive—and not merely hypothetical—security vulnerabilities.

U.S. national security, the U.S. energy sector, and the larger U.S. economy would be well served if CFIUS would treat energy transactions in a more rational manner. CFIUS should promulgate guidance regarding the types of energy assets that are likely to be considered critical infrastructure and should be willing to terminate reviews after the initial 30-day review for assets that are outside of the defined scope of critical infrastructure. Additionally, the pre-notice process should be more clearly defined and should not include requests for information outside of what is required by CFIUS regulations. If these changes were made, it would allow CFIUS to focus their resources on transactions that raise legitimate national security risks and would allow parties involved in most energy transactions to submit a notice to CFIUS with confidence that the review could be completed in a reasonable timeframe.

 

 

Preferred citation: Joshua C. Zive, Unreasonable Delays: CFIUS Reviews of Energy Transactions, 3 Harv. Bus. L. Rev. Online 169 (2013), https://www.hblr.org//?p=3271.

* Senior Counsel, Bracewell & Giuliani LLP.

[1] See, e.g., Foreign Investors Play Large Role in U.S. Shale Industry, U.S Energy Info. Admin. (Apr. 8, 2013), http://www.eia.gov/todayinenergy/detail.cfm?id=10711.

[2] See 50 U.S.C. app. § 2170(k) (2012).

[3] See generally Stephen K. Pudner, Moving Forward from Dubai Ports World—The Foreign Investment and National Security Act of 2007, 59 Ala. L. Rev. 1277, 1278–81 (2008); James F.F. Carroll, Back to the Future: Redefining the Foreign Investment and National Security Act’s Conception of National Security, 23 Emory Int’l L. Rev. 167, 167–68 (2009) (describing historical origins of CFIUS regulatory mandate).

[4] See Pudner, supra note 3, at 1281; 50 U.S.C. app. § 2170(e).

[5] Regulations Pertaining to Mergers, Acquisitions, and Takeovers by Foreign Persons, 56 Fed. Reg. 58,774, 58,775 (Nov. 21, 1991) (to be codified at 31 C.F.R. pt. 800).

[6] Id. at 58,786.

[7] Id.

[8] Id. at 58,787.

[9] Id. at 58,784–87.

[10] See Deborah M. Mostaghel, Dubai Ports World Under Exon-Florio: A Threat to National Security or a Tempest in a Seaport?, 70 Alb. L. Rev. 583, 583 (2007).

[11] See id. at 606.

[12] See id. at 607.

[13] Foreign Investment and National Security Act of 2007, Pub. L. No. 110-49, 121 Stat. 246 (2007).

[14] Regulations Pertaining to Mergers, Acquisitions, and Takeovers by Foreign Persons, 73 Fed. Reg. 70,702 (Nov. 21, 2008) (to be codified at 31 C.F.R. pt. 800).

[15] 50 U.S.C. app. § 2170(a)(5), (f)(6) (2012).

[16] Id. § 2170(b).

[17] Id.

[18] James K. Jackson, Cong. Research Serv., RS22197, The Exon-Florio National Security Test for Foreign Investment 4 (2006).

[19] 50 U.S.C. app. § 2170(a)(6).

[20] Id.

[21] Id. § 2170(f)(6) (emphasis added).

[22] Id.

[23] See 31 C.F.R. § 800.208 (2012)

[24] 50 U.S.C. app. § 2170(f)(6).

[25] See Mostaghel, supra note 10, at 595.

[26] 31 C.F.R. § 800.401(f) (2012).

[27] Id.

[28] Regulations Pertaining to Mergers, Acquisitions, and Takeovers by Foreign Persons, 73 Fed. Reg. 70,702, 70,711 (Nov. 21, 2008) (to be codified at 31 C.F.R. pt. 800).

[29] 31 C.F.R. § 800.402 (2012).

[30] Id. § 800.402(c)(6)(vi).

[31] See Filing Instructions, U.S. Dep’t of Treasury, http://www.treasury.gov/resource-center/international/foreign-investment/Pages/cfius-filing-instructions.aspx (last visited April 12, 2013).

[32] See Committee on Foreign Investment in U.S. (CFIUS), U.S. Dep’t of Treasury, http://www.treasury.gov/resource-center/faqs/CFIUS/Pages/default.aspx (last visited April 12, 2013) (“The time that it takes for the Staff Chairperson to determine that the notice complies with §800.402 after it has been submitted by the parties depends upon a variety of factors, including the notice itself and whether parties have submitted a draft notice before submitting the formal notice.”).

[33] See U.S.C. app. § 2170(a)(6) (2012).

[34] See Mostaghel, supra note 10, at 595.

[35] See 31 C.F.R. § 800.501(a)(2) (2012).

[36] 50 U.S.C. app. § 2170(b)(2)(B).

[37] See id. § 2170(a)(6).

[38] See 31 C.F.R. § 800.402 (2012) (listing all of the information regarding a transaction required for a complete notice).

[39] This practice is not reflected in any formal regulations or guidance, but in the author’s experience CFIUS treats post-closing filings with more skepticism, and will require a fulsome explanation of why the notice was not filed prior to closing.

[40] While the specifics of all such transactions are confidential, one need only to review the recent acquisition of Nexen Inc. by CNOOC to see an example where CFIUS approval took over six months. See Roberta Rampton & Scott Haggett, CNOOC-Nexen Deal Wins U.S. Approval, Its Last Hurdle, Reuters, Feb. 12, 2013, available at http://www.reuters.com/article/2013/02/12/us-nexen-cnooc-idUSBRE91B0SU20130212.

By

The Private Role in Public Fracturing Disclosure and Regulation

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Hannah J. Wiseman*

Abstract: Recent domestic growth in oil and gas natural gas production from shales and sandstones called “tight” formations—largely enabled by a modified technology called slickwater hydraulic fracturing—has driven both economic growth and environmental concerns. Public concerns have often focused on the chemicals used in the fracturing process, yet federal regulations requiring disclosure of chemicals are weak. In the midst of initial “threats” of federal intervention, industry—along with state regulators—developed a website that enabled chemical disclosure. State regulations later mandated disclosure through this website, or allowed it as one option within a mandatory disclosure regime. Independently, gas companies also have begun to experiment with less toxic fracturing chemicals and to take other substantive efforts toward identifying and limiting the risks of tight oil and gas development. This example of a public-private effort to enhance informational access in fracturing, and to make limited substantive changes, may offer important lessons for other oil and gas regulation moving forward. Agencies and policymakers must make independent assessments of risks and avoid directly adopting industry solutions if those solutions are incomplete or avoid needed change. But oil and gas operators have shown how public action, combined with industry coordination and innovation, can sometimes inspire productive responses to the risks of unconventional oil and gas production.

 

Introduction

As 2012 drew to a close, the International Energy Agency declared that the United States had experienced a “renaissance” in energy.[1] Indeed, while we have long relied on imports to fulfill many of our energy needs, recent expansions of drilling and hydraulic fracturing technologies have opened up large reserves of oil and gas in shales and other “tight,” densely packed formations underground, including sandstones. Becoming a major global supplier of oil and gas will have important economic, and some environmental, benefits for the United States, and potentially for the world; natural gas releases fewer conventional air pollutant emissions and greenhouse gas emissions than coal or oil, for example.[2] Yet domestic abundance of fuels also raises substantial concerns, including worries that gas will displace investments in the renewable technologies necessary to solve climate problems,[3] and that widespread extraction will cause environmental contamination.[4] Much of the initial public concern has focused on the chemicals used in fracturing and associated contamination risk.[5] Yet few federal environmental laws require disclosure of these chemicals in a manner accessible to the public.[6] Chemical use is not the only environmental concern associated with drilling and fracturing—indeed, it may be far from the largest concern.[7] But the potential for chemicals to spill while being transported to well sites or mixed with fracturing chemicals,[8] or for fracturing wastewater to be improperly treated prior to disposal,[9] makes knowledge of chemicals used at well sites one important component of understanding and addressing fracturing risks.

In response to public concerns about the known and unknown risks of drilling and fracturing,[10] a growing number of states have required operators to disclose the type and quantity of chemicals used at fractured well sites.[11] Industry’s involvement in driving and shaping these state regulations offers interesting initial lessons in public-private efforts at regulatory reform in drilling and fracturing,[12] and this Essay briefly explores this trend. Part I describes weak federal disclosure requirements, which, in part, drove public demands for change. Part II identifies public-private efforts to form a voluntary chemical disclosure website and explores state laws mandating disclosure—many of which require or allow disclosure through the website. Having identified this core public-private development, Part III describes other efforts, often instigated by coalitions of state regulators and industry members, to identify and respond to the risks of shale gas and oil development. Finally, Part IV draws from the literatures of new governance and voluntary industry behavior to analyze how industry might both inspire and constrain future substantive regulatory change, identifying both positive and negative lessons from the public-private experiment so far.

I.              Federal Disclosure Laws

Slickwater fracturing—a now-common technique that injects water and chemicals down wells at high pressure—has driven both oil and gas development and demands for information about the chemicals used in this development. Existing federal informational disclosure requirements for oil and gas production are weak, however. The Occupational Safety and Health Act and Emergency Planning and Community Right-to-Know Act require operators to keep material safety data sheets for chemicals on their sites;[13] these sheets describe the chemicals on site and their effects. Under federal law, operators also must provide these sheets to local emergency planning coordinators.[14] The public benefit of these laws, however, is limited: curious citizens would often have to physically travel to a well site or local emergency agency to gain access to the sheets, and, more importantly, operators can claim trade secret status for these chemicals, thus potentially blocking public access.[15]

As fracturing has become more common, and environmental and health concerns have expanded, the federal government has begun to respond. As part of a national study of the effects of fracturing on drinking water, the Environmental Protection Agency (EPA) demanded chemical information from the largest U.S. fracturing companies.[16] In its recent progress report on the study, the agency indicates that it has received chemical information from nine companies and obtained additional information from 12,000 voluntary “well-specific chemical disclosures” on FracFocus.[17] The Agency also requested information from several major operators in Pennsylvania about the quantity of wastewater generated from drilling and fracturing and how the operators treated, recycled, and or disposed of it.[18] Several federal senators and representatives, in turn, proposed disclosure requirements as part of a “FRACAct,” which died in committee.[19] The more meaningful efforts toward disclosing chemicals have occurred at the state and industry levels. Perhaps in part due to federal “threats,”[20] growing public demands for information, and competitive pressure, these entities took the lead in expanding the disclosure of chemicals used in hydraulically fractured wells.

II.           Public and Private Efforts Toward Disclosure

One of the first major steps toward disclosure of the chemicals used at each well site is a website called FracFocus.[21] The Ground Water Protection Council (GWPC)—a 501(c)(6) organization comprised of state oil and gas and environmental administrators[22]—worked with energy companies to fund, develop, and operate this website.[23] On FracFocus, energy companies voluntarily disclose the type and quantity of chemicals that they use at each well site, and more than 200 oil and gas companies have registered more than 27,000 well sites.[24] Curious investigators can click on each site to reveal a list of the specific chemicals used at that well.[25]

As voluntary disclosure has expanded, so, too, has regulation of disclosure. From 2010 through 2012, Arkansas,[26] Colorado,[27] Louisiana,[28] Michigan,[29] Mississippi,[30] Montana,[31] New Mexico,[32] New York,[33] North Dakota,[34] Ohio,[35] Oklahoma,[36] Pennsylvania,[37] Texas,[38] West Virginia,[39] and Wyoming[40] all updated, released, or proposed new statutes, agency directives, or regulations to require basic chemical disclosure. Nearly all of these laws require post-fracturing disclosure of the identity of chemicals used at well sites, a description of the quantity of each chemical used, and, often, a description of the quantity of water used.[41] Several of the laws provide that operators may either disclose information by submitting a form to the state oil and gas or environmental agency or by showing that they have submitted to FracFocus.org or other websites approved by the state.[42] North Dakota offers FracFocus as the sole means of disclosure and requires, within sixty days after fracturing, disclosure of all information “made viewable” by that website,[43] whereas Oklahoma allows submission on FracFocus or to the state oil and gas agency, which then posts on FracFocus.[44]

States are not simply incorporating FracFocus disclosure within public regulations; instead, they also appear to be modifying initial public-private efforts at disclosure. Colorado, for example, provides that if by 2013 FracFocus “does not allow the Commission staff and the public to sort the registry for Colorado information by geographic area, ingredient, chemical abstract service number, time period, and [well] operator” or “[t]here is no reasonable assurance that the registry will allow for such searches,”[45] then operators must use electronic forms created by the Colorado Oil and Gas Conservation Commission.[46]

The combination of voluntary industry disclosure and an expanding array of state disclosure laws—some of which are encouraging further innovation on the voluntary disclosure site—is promising. Nevertheless, some challenges remain. First, states consistently allow operators to claim that their chemicals retain trade secret protection and therefore should not be disclosed;[47] the federal laws allow the same claim.[48] It appears that only Texas has provided an appeal mechanism for trade secret claims—allowing surface owners near wells and certain state agencies to contest secrecy.[49] In a potentially more problematic development, states might view informational requirements as adequately addressing the new risks posed by higher levels of drilling and fracturing.[50] Comprehensive modifications of oil and gas regulations in some states, and the emerging literature on risks,[51] suggest that informational requirements will not be adequate, yet they could provide a false sense of security to regulators.

III.         Other Private and Public-Private Efforts to Respond to Environmental Concerns

Perhaps in part due to the wave of disclosure, which could incentivize industry to reduce its environmental impacts,[52] private and quasi-private actors have begun to take other steps to address concerns associated with the use of chemicals in tight oil and gas development. These efforts have been both informational and substantive.

On the informational end, several organizations have enhanced efforts to compare and describe the substance of state oil and gas regulations, including regulation to prevent contamination of water with drilling or fracturing chemicals. The GWPC published a white paper for the Department of Energy addressing state regulations that protect groundwater, including requirements for casing (lining) wells and properly cementing the casing.[53] It also operates a Risk Based Data Management System, in which “[m]ore than twenty-two regulatory agencies . . . [track] oil, gas, injection well, and source water protection activities.”[54] Further, the Interstate Oil and Gas Compact Commission (IOGCC)—a group of state and international representatives that is Congressionally-commissioned but receives some industry funding[55]—has a website called “Groundwork,” which allows viewers to compare state oil and gas laws.[56] FracFocus, operated by both the GWPC and the IOGCC, also contains some state regulations and updates on recent regulatory changes, as well as state agency contact information.[57] In one of the most comprehensive informational efforts to date, the Intermountain Oil and Gas Project—a partnership between the University of Colorado Law School and a number of NGOs, academic groups, and industry actors[58]—collects state and federal regulations.[59]

These informational developments are important: because states currently have the primary responsibility for regulating oil and gas development, better information sharing is necessary if an effective laboratory of the states is to emerge in lieu of federal regulation. States and stakeholders must be aware of the substantial variations in regulation that exist,[60] and they must better understand how the “leader” states have developed new regulations to reduce risks. None of the existing regulatory information-sharing efforts, however, provide a comprehensive database that allows users to review and compare regulations among all states either by regulatory subject matter or state.[61]

Several of the private-public documents and websites comparing or describing information about regulation also contain normative statements about the “best” level of regulation or the importance of oil and gas development. The GWPC’s document comparing state regulations concludes that “[s]tate oil and gas regulations are adequately designed to directly protect water resources.”[62] Separately, the GWPC also has issued a resolution opposing federal regulation of the fracturing process.[63] The IOGCC’s information page on state regulations, in turn, contains a link stating: “Why Environmentalists Should Support Oil Exploration in Alaska’s Arctic Waters.”[64] These normative statements detract from the value of the information provided, threatening to turn away certain users and, in some cases, potentially mis-portray the effectiveness of regulation based on the organization’s political mission. The same risk, of course, attaches to nongovernmental organization (NGO) websites that describe state regulations and tend to oppose oil and gas development within these same descriptive efforts.[65]

Some public-private efforts have moved beyond informational initiatives: several nonprofits and quasi-private groups recommend or suggest specific types of regulation to reduce the risks of drilling and fracturing and, in some cases, these proposals become part of regulation. Through the IOGCC charter, states historically agreed to pass basic regulations to prevent oil and gas waste in the production process and basic safety and environmental problems, including regulations to prevent excessive fire hazards at oil and gas sites and conserving oil and gas.[66] And under a more modern initiative, the GWPC has advocated against the use of diesel fuel in fracturing,[67] although the EPA, which has rare authority in this area, has not banned it.[68] The Secretary of Energy Advisory Board’s Natural Gas Subcommittee, convened by the Secretary of Energy and including professors, environmental group representatives, and energy research groups,[69] similarly recommended banning the use of diesel in fracturing and suggested a number of other needed regulatory improvements in two reports issued in 2011.[70]

The State Review of Oil and Natural Gas Environmental Regulations (STRONGER)—a collaboration of state agency members, environmental NGOs, and industry representatives[71]—has larger sets of guidelines that encourage the proper disposal of oil and gas wastes.[72] Working from these guidelines, the organization voluntarily reviews state oil and gas regulatory programs to make recommendations for improvements.[73] The organization recently updated its guidelines to include fracturing-specific standards[74] and has reviewed a number of state hydraulic fracturing programs.[75] The organization often provides recommendations for substantive regulatory change after its review. In Louisiana, for example, STRONGER noted that the state lacked specific standards for the cementing of liners into wellbores that would be fractured and thus would experience higher pressures inside the well.[76] Adequate cementing of liners into the well is necessary to prevent wells from leaking oil, gas, or other substances into groundwater, but so far, the state has only updated its disclosure requirements in response to the STONGER review.[77] The American Petroleum Institute also has a variety of drilling and fracturing standards, best management practices, and guidelines[78] that some states have selectively incorporated into regulation,[79] and the Society of Petroleum Engineers has partnered with industry, government officials, and environmental groups to identify the risks of fracturing through organized “summits” of experts.[80] The GWPC has similarly organized forums on identifying risks and developing best practices in fracturing,[81]

These private and quasi-private efforts of course fail to address all of the potential risks of tight oil and gas development. Their guidelines, resolutions, and summits do not cover all of the chemicals used in drilling and fracturing, and they may miss or ignore many other relevant stages of well development.[82] Further, even for the risks identified through private and quasi-private initiatives, regulators have not always responded.[83]

In some cases, deficiencies in public-private efforts to encourage better regulation may be offset by industry efforts at self-regulation. The American Petroleum Institute’s (API) detailed guidelines[84] for drilling and fracturing may be very effective if consistently followed, for example. Some companies are also commencing substantive initiatives to use fewer toxic chemicals in fracturing, which may result from efforts to improve public image[85] and save money.[86] The program of one large energy actor “calls for the elimination of any additive not critical to the successful completion of the well” and “determines if greener alternatives are available for all essential additives.”[87] Other companies have developed “low-footprint” fracturing operations that use less surface area and have implemented zero spill technology to avoid surface pollution during drilling and fracturing.[88]

All of these public-private efforts toward sharing regulatory information, suggesting better regulation, and developing industry best-practices are valuable but may fail to address all of the risks. Substantive efforts to self-regulate are voluntary, meaning that members may ignore best practices without penalty. These efforts also may be influenced by a strong interest, shared by industry and many state regulators, to keep regulation at the state level.[89] And in the case of industry efforts, profit motives could potentially dampen best practices aimed to reduce environmental risks. Despite all of these drawbacks, public-private efforts beyond chemical disclosure in tight oil and gas development seem to be expanding the regulatory information available to the public, reducing the use of certain chemicals, and potentially lowering certain development risks.

IV.         Lessons for Future Fracturing Regulation

The industry’s information-based and substantive efforts in the drilling and fracturing area, coupled with formal public requirements, are interesting variations on several familiar themes, including new governance and voluntary improvement of environmental performance. This Part briefly explores how the evolution of disclosure laws and some substantive standards in drilling and fracturing may fit within these themes, and how further improvements will be needed to ensure effective regulation of oil and gas development through a combination of public and private controls.

A.            Collaborative Governance

A broad environmental literature, and ever-growing scholarship within the field of new governance, has noted a move away from public law as we traditionally understand it. Whereas scholars previously envisioned legislatures and agencies implementing top-down, mandatory statutes and regulations to control various risks, many now understand the regulatory process as a more complex endeavor, involving multiple stakeholders in forming and implementing regulation. As Professor Bradley Karkkainen explains, new governance moves us “away from the familiar model of command-style, fixed-rule regulation by administrative fiat, and toward a new model of collaborative, multi-party, multi-level, adaptive, problem-solving.”[90] This builds from, among other foundations, Jody Freeman’s model of collaborative governance, which requires a “problem-solving orientation” focused on “solving regulatory problems; “[p]articipation by interested and affected parties in all stages of the decisionmaking process”; a view of rules as temporary, not fixed solutions; accountability of all parties to each other, including public and private parties; and a flexible agency that convenes negotiations among stakeholders and developers solutions based on participant contributions.[91]

In the environmental realm, one of the most common examples of new governance is Project XL, in which industry actors could avoid federal environmental regulation by showing that they had implemented alternative methods to achieve superior environmental protection.[92] Other examples come from rulemaking rather than rule application. Through negotiated rulemaking, or reg-neg, agencies involve regulated actors and concerned parties more closely in the rule drafting process, often arriving at consensus standards.[93] Stakeholders share information about actual risks and industry’s approaches to them, debate the merits of these approaches, and, if successful, arrive at a rule that better encompasses genuine concerns and does so in an effective and cost-efficient manner.[94]

Public-private efforts to improve environmental performance in drilling and fracturing exhibit several traits of potentially successful collaborative governance strategies. Industry’s FracFocus website appears to have influenced the content of many state disclosure rules; even if formal negotiated rulemaking did not occur within these rulemaking processes,[95] state environmental and oil and gas agencies clearly took into account the FracFocus disclosure requirements and often incorporated them into disclosure requirements. This is important, in that agencies at least indirectly considered regulated actors’ views about reasonable disclosure and, perhaps, what industry believed was most effective at informing the public.[96] In enacting disclosure laws, some states also specifically addressed recommendations by STRONGER.[97] Furthermore, many state disclosure rules are intentionally impermanent, with Colorado allowing disclosure on FracFocus but only if the website eventually allows individuals to search by certain criteria.[98]

Despite these promising developments, there are important limitations in states’ reliance on industry suggestions for disclosure. As introduced in Part II, all disclosure rules—with the exception of Texas (if appeals of trade secret status are successful), and possibly West Virginia[99]—appear to allow those reporting chemical use to retain trade secret status for chemicals,[100] and industry actors that can hide the identity of certain toxic substances may have few incentives to stop using these substances. Further, in crafting disclosure regulations, states may have ignored other important information that should be disclosed but has not been prioritized by industry, such as the type of soil at the well site, whether the site is above an aquifer or near surface water, and other environmental indicators that would determine the impact of the chemical if it spilled or leaked from the well.[101]

In the substantive realm, efforts by state regulators and industry to work together to identify risks, write guidelines, and propose regulatory changes have been impressive, although not comprehensive. Yet even agreed-upon suggestions for improved performance have not morphed into regulation in some cases, with the EPA rejecting the GWPC’s proposal to ban diesel in fracturing, for example.[102] In sum, public-private efforts toward improving both information disclosure and drilling and fracturing practices have been important yet have occurred in a piecemeal fashion, and they are likely inadequate to fully address risks. More consistent efforts to compare gaps among states and regulatory change in response to suggestions from STRONGER, industry groups, scientists, and other stakeholders will be needed.

B.            Voluntary Improvement of Environmental Performance

In another area of the literature that recognizes that command and control regulation is not in all cases the only means of achieving sound environmental performance, scholars have noted a variety of mechanisms that may drive industries to self-regulate or over-perform on a broad set of environmental measures. Professors Daniel Esty, Peter Appel, Dennis Hirsch and other environmental and administrative law scholars have pioneered this field, observing that sheer profit incentives,[103] as well as regulatory programs that encourage innovation, can inspire self-driven improvement. As Professor Appel notes, environmental problems are caused largely by corporate actors that generate externalities—many of which are diffuse and not immediately recognizable.[104] Yet corporations, including management and stockholders, can benefit immensely from improvements in environmental performance, and the challenge lies in creating the right incentives to encourage voluntary improvements.[105] Information disclosure regimes,[106] or requirements for enhanced technological monitoring of pollution,[107] could improve performance simply by embarrassing industry actors, or by creating better-informed regulation. Threats of regulation also may work by incentivizing industry to prove sound environmental performance and preempt the need for regulation,[108] while some corporations may reduce pollution or other environmental harms in response to shareholder concerns—or at least pretend to take such efforts.[109]

Industry actors, by voluntarily disclosing information about chemicals used at well sites, appear to have stepped up pressure on nonconforming actors, challenging them to follow the emerging norm of transparency. Industry—likely in part due to threats of regulation,[110] and in part due to public and peer pressure[111]—has voluntarily disclosed the chemicals that it uses at thousands of well sites[112] and has initiated efforts to employ less toxic fracturing chemicals and other environmentally beneficial practices.[113] And as discussed in Part II, many states have implemented mandatory disclosure regimes that rely on FracFocus. Under a metric that, in another context, Professor Karkkainen believes is important for enhancing substantive performance through regulation, the information collected allows direct comparison of environmental performance;[114] chemicals used are reported in the same units of volume,[115] and news reporters and other groups have begun to use the information to suggest areas where risk remains.[116]

As shown by private and quasi-private efforts toward informational and substantive changes in tight sands and oil and gas development, not all private initiatives lead to regulatory change. In some cases, this may be acceptable both from a risk and an efficiency perspective. If all companies followed a full suite of best practices, in which an industry leader verified compliance, then regulation might not be necessary. Similarly, if governments converted every voluntary agency initiative, such as FracFocus, into regulation, they might stifle industry innovation.

To the extent there remain risks from handling chemicals and engaging in the many stages of tight oil and gas development, however, public agencies need to become more proactive. In many cases, the oil and gas industry itself may be unaware of the risks as the scale of oil and gas drilling dramatically rises in certain regions and fracturing is used more frequently;[117] this uncertainty[118] will limit the effectiveness of self-regulation that might reduce the risk of pollution liability and other threats to a company’s value. States and the federal government, also operating under uncertainty, need to expand efforts to work collaboratively with stakeholders, including industry, scientists, and nonprofit groups to conduct risk assessments and identify regulatory needs. If borrowing from industry efforts to substantively improve performance, states must ensure that they are not boxed in by the approach chosen by industry. The solution first implemented often becomes the long-term solution, yet it may not be the best one. Although FracFocus encourages energy companies to disclose a variety of information types, for example—from the volume of water used at each well to the names and types of chemicals—it does not have a space for describing the natural resources near the well site or soil conditions on the site, which could substantially influence the impact of a chemical spill.

Finally, agencies that incorporate industry standards into regulation must modify these standards to incorporate the views of non-industry actors. Public regulations, as opposed to best practices, exist for several reasons: they balance a number of interests, including public demands for environmental and public health protection and industry demands for efficiency; they often incorporate scientific data and careful calculations of costs and benefits; and they are mandatory. Generally, public regulations encourage all members of an industry to act consistently and thus to achieve the overall goal of the regulation, such as a maximum level of contaminants in air or water. While industry often holds the most technical knowledge in oil and gas, and thus is a key actor within the regulatory process, it is not and should not be the only voice that influences regulation.

Conclusion

As tight oil and gas development continues its rapid march toward domination of the U.S. energy market, both industry and government actors—often working in concert—are responding in a variety of ways. This Essay has introduced several of the private and public-private efforts to address the risks of this development and appease public concerns. One of the most successful efforts to date has involved the expansion of chemical disclosure, with voluntary industry efforts morphing into state regulations that require disclosure through a public-private website.

Similar initiatives have emerged in more substantive areas. Private and public-private efforts to disseminate information about the content of state oil and gas regulations have provided useful, although incomplete, means of comparing regulatory content. Similar efforts to identify risk and propose improved regulation—although not always implemented—also appear to be somewhat successful. And finally, private best practices provide some industry self-regulation of risks.

More action, both at the public and private levels and the grayer areas between them, will be needed to address the range of impacts introduced by a rapidly growing industrial practice. Local, state, and federal agencies implementing further change must account for and in some cases formalize the private progress already occurring, while recognizing that such action could disincentivize future industry efforts. At the same time, private actors seeking public acceptance of tight oil and gas would be wise to further improve information dissemination and show the extent to which industry actors follow the many best practices that already have been developed. Disclosure is a very important start, but much more collaborative work remains to be done.

Preferred Citation: Hannah J. Wiseman, The Private Role in Public Fracturing Disclosure and Regulation, 3 Harv. Bus. L. Rev. Online 49 (2013), https://www.hblr.org//?p=2770.

* Assistant Professor, Florida State University College of Law. J.D., Yale Law School, A.B., Dartmouth College. Professor Wiseman’s research explores the role of changing regulation and regulatory strategies in protecting the character of living spaces and environmental quality, from the sub-local to the national level.

[1] Int’l. Energy Agency, World Energy Outlook 74 (2012), available at http://www.oecd-ilibrary.org/error/authentication;jsessionid=hffgs367hw43.x-oecd-live-01 (not accessible by the public without payment; on file with author).

[2] U.S. Energy Info. Admin., Natural Gas 1998: Issues and Trends 53 fig.22 (1999), http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/natural_gas_1998_issues_trends/pdf/it98.pdf. The extent of greenhouse gas emissions reductions is debated. however, in light of potent methane emissions from natural gas. See Mark Fulton et al., Worldwatch Institute, Comparing Life-Cycle Greenhouse Gas Emissions from Natural Gas and Coal 3 (Aug. 25, 2011), http://www.worldwatch.org/system/files/pdf/Natural_Gas_LCA_Update_082511.pdf (comparing lifecycle assessments).

[3] See, e.g., cf. See International Energy Agency, Are We Entering a Golden Age of Gas 8–9 (2011), available at http://www.worldenergyoutlook.org/media/weowebsite/2011/WEO2011_GoldenAgeofGasReport.pdf (noting that with a rise in global natural gas use through 2035, global carbon dioxide emissions would still rise and that problematic warming would likely occur); Thomas Friedman, Op-Ed, Get It Right on Gas, N.Y. Times (Aug. 5, 2012), http://www.nytimes.com/2012/08/05/opinion/sunday/friedman-get-it-right-on-gas.html (quoting Faith Birol, Chief Economist, International Energy Agency) (“[A] golden age for gas is not necessarily a golden age for the climate’—if natural gas ends up sinking renewables.”).

[4] See, e.g., Daniel J. Rozell & Sheldon J. Reaven, Water Pollution Risk Associated with Natural Gas Extraction from the Marcellus Shale, 32 Risk Analysis 1382, 1384 (2011), http://onlinelibrary.wiley.com/doi/10.1111/j.1539-6924.2011.01757.x/pdf (estimating potentially large quantities of surface spills of contaminants as a result of drilling and fracturing in the Marcellus Shale).

[5] See, e.g., Hannah J. Wiseman, Risk and Response in Fracturing Policy, 84 U. Colo. L. Rev. (forthcoming 2013), available at http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2017104 (describing concerns expressed by members of Congress, scientists, and citizens).

[6] See infra note 15 and accompanying text.

[7] See, e.g., Wiseman, supra note 5 (discussing potential risks based on recent violations at well sites and some of the initial literature on risk, and highlighting concerns in addition to the environmental impacts of fracturing chemicals).

[8] See, e.g., id.; Rozell & Reaven, supra note 4.

[9] See, e.g., Letter from Shawn M. Garvin, EPA Region III, Adm’r, to Michael Krancer, Acting Sec’y, Penn. Dep’t of Envtl. Prot. (May 12, 2011), available at http://www.epa.gov/region03/marcellus_shale/pdf/letter/krancer-letter5-12-11.pdf. (expressing continuing concerns about inadequately-treated wastewater from fracturing).

[10] U.S. Gov’t Accountability Office, GAO-12-732, Oil and Gas: Information on Shale Resources, Development, and Environmental and Public Health Risks 4 (2012) (concluding that risks cannot currently be quantified due to a lack of adequate scientific information).

[11] See infra notes 26–40.

[12] This paper does not fully explore the new governance and self-regulatory implications of disclosure laws. Rather, it provides a brief introduction to industry initiatives in drilling and fracturing and simultaneous government responses and very briefly addresses these theoretical areas.

[13] Emergency Planning and Community Right-to-Know Act of 1986 §§ 311–312, 42 U.S.C. §§ 11021–11022 (2011).

[14] Id. at § 311(c)(1), 42 U.S.C. § 11021(c)(1).

[15] Id. at §§ 312–313, 42 U.S.C. §§ 11021–11022; 29 C.F.R. § 1910.1200(i) (2010). See also Hannah Wiseman, Trade Secrets, Disclosure, and Dissent in a Fracturing Energy Revolution, 111 Columb. L. Rev. Sidebar 1 (2011), http://www.columbialawreview.org/wp-content/uploads/sites/18/2011/01/1_Wiseman.pdf (describing the limits of federally-required disclosure). Although public records requests might be successful, states sometimes require on-site file reviews in order for citizens to obtain records.

[16] Letter from the Envtl. Prot. Agency to BJ Services et al. (Sept. 9, 2010), available at http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/upload/HFvolu

ntaryinformationrequest.pdf.

[17] Envtl. Prot. Agency, Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report 2 (2012), http://www.epa.gov/hfstudy/pdfs/hf-report20121214.pdf.

[18] See Enclosure 1, Letter from Shawn M. Garvin, Regional Adm’r, EPA Region III, to Freddie Kotek, Chief Exec. Officer, Atlas Res., L.L.C. (May 12, 2011), available at http://www.epa.gov/region03/marcellus_shale/pdf/letter/enclosures5-12-11.pdf.

[19] Fracturing Responsibility and Awareness of Chemicals Act of 2011, S. 587, 112th Cong. (2011), available at http://www.govtrack.us/congress/bills/112/s587/text; H.R. 1084, 112th Cong. (2011), available at http://www.gpo.gov/fdsys/pkg/BILLS-112hr1084ih/pdf/BILLS-112hr1084ih.pdf.

[20] Tim Wu, Agency Threats, 60 Duke L.J. 1841, 1844, 1849-51 (2011) (describing private threats, such as “a warning letter sent to a company,” and public threats, such as a “threat of either new rulemaking or enforcement of an existing rule,” and arguing that especially for industries “in a state of high uncertainty,” threats can be superior to rules in terms of forcing entities to act in the public interest without entrenching rules that could be “bad law”). But see id. at 1846–48 (surveying the literature on threats and noting that it largely views threats as negative).

[21] FracFocus Chemical Disclosure Registry, http://fracfocus.org/ (last visited Nov. 24, 2012) [hereinafter FracFocus].

[22] About Us, Groundwater Prot. Council, http://www.gwpc.org/about-us (last visited Nov. 24, 2012).

[23] FracFocus, supra note 21 (showing the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission—which receives industry funding—as holders of the website copyright and as website sponsors).

[24] About Us, FracFocus Chemical Disclosure Registry, http://fracfocus.org/welcome (last visited Nov. 24, 2012).

[25] Well Map, FracFocus Chemical Disclosure Registry, http://www.fracfocusdata.org/fracfocusfind/ (last visited Nov. 24, 2012).

[26] 178 Ark. Code R. § B-19(k) (LexisNexis 2012), available at http://www.aogc.state.ar.us/onlinedata/forms/rules%20and%20regulations.pdf (showing new rule effective January 15, 2011).

[27] 2 Colo. Code Regs. § 404-1:205A (Westlaw 2012) (applying to “hydraulic fracturing treatments performed on or after April 1, 2012”).

[28] La. Admin. Code tit. 43:XIX, § 118(C)(1) (Westlaw 2012) (promulgated October 2011).

[29] Mich. Dep’t of Envtl. Quality, Supervisor of Wells Instruction 1-2011 3 (2011), available at www.michigan.gov/documents/deq/SI_1-2011_353936_7.pdf.

[30] Miss. Sec’y of State, Rule 1.26 Requirements for Hydraulic Fracture Stimulation—Report of Shooting or Treating, http://www.sos.ms.gov/ACProposed/00018951b.pdf.

[31] Mont. Admin. R. 36.22.1015(2) (Westlaw 2011).

[32] Proposed, N.M. Code R. 19.15.16.18 (2011), available at http://www.emnrd.state.nm.us/ocd/documents/201111-2OCDModifications.pdf; Gabrielle A. Gerholt, N.M Oil Conservation Div., Updated Information on NM Hydraulic Fracturing Disclosure Form, Indep. Petrol. Ass’n of N.M, http://www.ipanm.org/article.php/OCD_HF_Disclosure (last visited June 18, 2012) (indicating that rules have been finalized).

[33] N.Y. Dep’t of Envtl. Conservation, Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, and Solution Mining Program 8-30 to -31 (2011), available at http://www.dec.ny.gov/data/dmn/rdsgeisfull0911.pdf (proposed—not yet finalized).

[34] N.D. Admin. Code 43-02-03-27.1(2)(i) (Westlaw 2012) (effective April 1, 2012).

[35] Ohio Rev. Code Ann. § 1509.10 (Westlaw 2012).

[36] Okla. Admin. Code § 165:10-3-10 (Westlaw 2012) (effective July 2012), available at http://www.occeweb.com/rules/Web%20Ready%20Ch10%20FY13%2007-01-12%20searchable.pdf.

[37] 58 Pa. Stat. § 3222(b.1)(1)(i) (Westlaw 2012).

[38] 16 Tex. Admin. Code § 3.29(c)(2)(A)(ix)–(xi) (Westlaw 2012).

[39] W. Va. Code § 22-6A-7 (Westlaw 2012).

[40] 55-3 Wyo. Code R. § 45(d) (LexisNexis 2012). Note that this is not an exhaustive list. Other states also may have recently updated their disclosure laws. For a helpful recent summary, see Brandon J. Murrill & Adam Vann, Cong. Research Serv., R42461, Hydraulic Fracturing: Chemical Disclosure Requirements (2012), http://www.fas.org/sgp/crs/misc/R42461.pdf.

[41] See sources cited supra notes 29–40. See also Hannah Wiseman & Francis Gradijan, Regulation of Shale Gas Development, Including Hydraulic Fracturing 88–89, tbl.7a (Univ. of Tulsa Legal Studies, Research Paper No. 11, 2011), available at http://papers.ssrn.com/sol3/papers.cfm?abstract_id=1953547 (describing the contents of the disclosure requirements).

[42] See, e.g. La. Admin. Code tit. 43:XIX, § 118(C)(4) (Westlaw 2012); Mont. Admin. R. 36.22.1015(4) (Westlaw 2012); Miss. Sec’y of State, supra note 30. See also FracFocus, supra note 21 (showing a total of eight states that allow disclosure through FracFocus).

[43] See N.D. Admin. Code 43-02-03-27.1(2)(i) (Westlaw 2012).

[44] Okla. Admin. Code 165:10-3-10(b) (effective July 2012).

[45] 2 Colo. Code Regs. § 404-1:205A(b)(3)(A) (Westlaw 2012).

[46] 2 Colo. Code Regs. § 404-1:205A(b)(3)(B) (Westlaw 2012).

[47] See Wiseman & Gradijan, supra note 41, at 90 tbl.7b. But see W. Va. Code § 22-6A-7 (Westlaw 2012). (appearing to not allow trade secret claims by simply requiring operators to submit “[a] listing of anticipated additives that may be used” and a “listing of the additives actually used”). I am grateful to Professor Keith Hall for flagging the West Virginia omission in a conversation on January 5, 2013.

[48] See Wiseman, supra note 15.

[49] 16 Tex. Admin. Code § 3.29(c)(4), (f)(1)(Westlaw 2012).

[50] Three shale gas states, including Louisiana, Oklahoma, and Texas, have implemented disclosure requirements yet few other revisions. This may be changing, however. Oklahoma is considering revisions to regulations in its “five-year strategic plan.” STRONGER, Oklahoma Hydraulic Fracturing State Review 4 (2011), available at http://www.strongerinc.org/documents/Final%20Report%20of%20OK%20HF%20Review%201-19-2011.pdf. Texas is considering relatively comprehensive revisions. See Memorandum from Cristina Self, Attorney, Office of Gen. Counsel, to Barry Smitherman, David Porter, and Buddy Garcia, Chairman and Comm’rs, R.R. Comm’n of Tex. (Aug. 21, 2012), www.rrc.state.tx.us/rules/prop-amend-3-13-Aug21-2012.pdf.

[51] See, e.g., Daniel J. Rozell & Sheldon J. Reaven, Water Pollution Risk Associated with Natural Gas Extraction from the Marcellus Shale, 32 Risk Analysis 1382 (2012), available at http://onlinelibrary.wiley.com/doi/10.1111/j.1539-6924.2011.01757.x/pdf (describing the total potential volume of spills from fracturing and drilling in the Marcellus); Wiseman, supra note 5, at 36–38 (describing spill incidents).

[52] There is a rich literature on how information disclosure requirements, or voluntary disclosure, encourages or fails to incentivize improved substantive performance, which I only touch upon in passing here. See, e.g., David W. Case, The Law and Economics of Environmental Information as Regulation, 31 Envtl. L. Rep. 10,773 (2001) (providing a literature review); David W. Case, Corporate Environmental Reporting as Informational Regulation: A Law and Economics Perspective, 76 U. Colo. L. Rev. 379, 385–86 (2005) (noting disagreement as to whether disclosure programs such as the Toxic Release Inventory—which requires certain industries to annually report their toxic emissions—lead to better environmental performance, but noting general agreement that TRI reporting “has induced significant voluntary reductions in covered releases well below levels otherwise required by existing command-and-control regulation” and has incentivized industry to periodically submit reports that describe all environmental performance in one document); id. at 381, n. 11 (citing to other sources); Bradley C. Karkkainen, Information as Environmental Regulation: TRI and Performance Benchmarking, Precursor to a New Paradigm?, 89 Geo. L.J. 257, 287 (2001) (noting that “[g]overnment regulation has long mandated information disclosure as a regulatory device” but that the TRI requires disclosure of “environmental performance of those parties most directly responsible for significant environmental impacts” and has been successful).

[53] Ground Water Prot. Council, State Oil and Natural Gas Regulations Designed to Protect Water Resources (2009), available at http://www.gwpc.org/sites/default/files/state_oil_and_gas_regula”tions_designed_to_protect_water_resources_0.pdf (prepared for DOE).

[54] Risk Based Data Management System, Ground Water Prot. Council, http://www.gwpc.org/programs/rbdms (last visited Nov. 25, 2012).

[55] 2012 Annual Meeting, Interstate Oil and Gas Compact Commission, http://www.iogcc.state.ok.us/sanantonio (last visited Nov. 25, 2012) (showing various energy companies as 2012 annual meeting sponsors); Member States, Interstate Oil and Gas Compact Commission, http://www.iogcc.state.ok.us/member-states (last visited Nov. 25, 2012).

[56] Interstate Oil & Gas Compact Comm’n, Groundwork, http://groundwork.iogcc.org/ (last visited Nov. 25, 2012).

[57] Regulations by State, FracFocus, http://fracfocus.org/regulations-state (last visited Nov. 25, 2012).

[58] Further Research, Intermountain Oil and Gas Project, http://www.oilandgasbmps.org/resources/links.php (last visited Dec. 11, 2012) (listing project partners and resources).

[59] Hydraulic Fracturing, Intermountain Oil and Gas Project, http://www.oilandgasbmps.org/resources/fracing.php (last visited Dec. 11, 2012).

[60] See Wiseman & Gradijan, supra note 41 (describing variations).

[61] For an initial effort to provide this type of comparison, see Wiseman & Gradijan, supra note 41, comparing regulations by subject matter for fifteen states in tables throughout the document.

[62] Ground Water Prot. Council, supra note 53, at 7.

[63] Ground Water Prot. Council, Resolution 03-5: Requesting Legislative Clarification of the Definition of “Underground Injection” in the Safe Drinking Water Act (2003), http://www.gwpc.org/sites/default/files/Res-03-5.pdf.

[64] Interstate Oil & Gas Compact Comm’n, supra note 56.

[65] See, e.g., Halliburton Loophole, Earthworks, http://www.earthworksaction.org/issues/detail/inadequate_regulation_of_hydraulic_fracturing (last updated Nov. 25, 2012).

[66] See Interstate Oil and Gas Commission Charter, Interstate Oil and Gas Compact Commission, http://www.iogcc.state.ok.us/charter (last visited Nov. 25, 2012).

[67] Ground Water Prot. Council, Resolution 02-2: Concerning the Use of Diesel Fuel in Fracturing Fluids in Underground Sources of Drinking Water (2002), http://www.gwpc.org/sites/default/files/Res-02-2.pdf.

[68] Envtl. Prot. Agency, Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels – Draft: Underground Injection Control Program Guidance # 84 (2012), http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/upload/hfdieselfuelsguidance508.pdf. But see Mike L. Krancer, Sec’y., Penn. Dep’t of Envtl. Prot., Hydraulic Fracturing: Facts, History, Context and Perspective, Presentation at the American Bar Association Section of Environment, Energy, and Resources, 20th Section Fall Meeting 5–6 (Oct. 13, 2012) (arguing that the EPA has gone too far in regulating fracturing with diesel).

[69] Members of the Subcommittee, Nat. Gas Subcommittee of the Secretary of Energy Advisory Board, http://www.shalegas.energy.gov/aboutus/members.html.

[70] Sec’y of Energy Advisory Bd., Shale Gas Production Subcommittee 90-Day Report 24–25 (2011), http://www.shalegas.energy.gov/resources/081811_90_day_report_final.pdf; Sec’y of Energy Advisory Bd., Shale Gas Production Subcommittee Second Ninety Day Report 4, 17 (2011), http://www.shalegas.energy.gov/resources/111811_final_report.pdf.

[71] Our Team, STRONGER, http://www.strongerinc.org/content/voting-members (last visited Nov. 25, 2012).

[72] STRONGER Guidelines, STRONGER, http://www.strongerinc.org/stronger-guidelines (last visited Nov. 25, 2012).

[73] State Reviews, STRONGER, http://www.strongerinc.org/process (last visited Nov. 25, 2012).

[74] Memorandum from the STRONGER Board to Pers. Interested in the Hydraulic Fracturing Guidelines (Feb. 8, 2010), http://67.20.79.30/sites/all/themes/stronger02/downloads/HF%20Guideline%20Web%20posting.pdf.

[75] Past Reviews, STRONGER, http://www.strongerinc.org/past-reviews (last visited Nov. 25, 2012).

[76] STRONGER, Louisiana Hydraulic Fracturing State Review 12 (2011), available at http://dnr.louisiana.gov/assets/OC/haynesville_shale/071311_stronger_review.pdf (“The review team recommends that the Office of Conservation develop casing standards to meet anticipated pressures and protect other resources . . . .”).

[77] See DNR Office of Conservation Adopts New Regulation for Hydraulic Fracture Operations in Louisiana, La. Department of Nat. Resources (Oct. 20, 2011) (showing that the new rule requires operators to acquire a work permit and disclose chemicals and that the rule was recommended in a STRONGER review); See also La. Admin. Code tit. XIX, § 118 (Westlaw 2012).

[78] See Am. Petrol. Inst., Overview of Industry Guidance/Best Practices on Hydraulic Fracturing, http://www.api.org/~/media/Files/Policy/Exploration/Hydraulic_Fracturing_InfoSheet.pdf (pointing readers to several API documents containing guidelines and standards); API – Drilling Collection, IHS, http://www.ihs.com/products/industry-standards/org/api/drilling/index.aspx (last visited Dec. 11, 2012) (listing documents containing numerous drilling standards and recommended practices).

[79] See, e.g., Md. Code Regs. 26.19.01.10(P) (Westlaw 2012) (requiring API Class A cement); 25 Pa. Code § 78.85 (2011) (requiring surface casing cement “that meets or exceeds the ASTM International C 150, Type I, II or III Standard or API Specification 10”); W. Va. Code R. § 35-4-11.5 (requiring “American Petroleum Institute Class A Ordinary Portland cement”); Wyo. Oil & Gas Conservation Comm’n, Guideline for Spill Cleanup (2002), available at http://wogcc.state.wy.us/craig/spill.htm (requiring operators to follow API’s “contaminated soil remediation ranking system” for certain spills).

[80] Soc’y of Petrol. Eng’rs, White Paper on SPE Summit on Hydraulic Fracturing 1, 5–6 (2011).

[81] See, e.g., Two National Water Events… ONE GREAT LOCATION!, Ground Water Prot. Council, http://www.gwpc.org/sites/default/files/events/AF12_Agenda_Dev_0917.pdf (last visited Nov. 25, 2012) (agenda for an industry-sponsored event, showing best practices panels).

[82] See Wiseman, supra note 51.

[83] See generally Wiseman, supra note 5 (arguing that regulatory responses to certain risks have been inadequate).

[84] Am. Petrol. Inst., Hydraulic Fracturing Operations—Well Construction and Integrity Guidelines (2009), available at http://www.api.org/~/media/Files/Policy/Exploration/API_HF1.pdf; Am. Petrol. Inst., Water Management Associated with Hydraulic Fracturing (2010), available at http://www.api.org/~/media/Files/Policy/Exploration/HF2_e1.pdf; Am. Petrol. Inst., Practices for Mitigating Surface Impacts Associated with Hydraulic Fracturing (2011), available at http://www.api.org/~/media/Files/Policy/Exploration/HF3_e7.pdf.

[85] See supra note 52 for a discussion of the broader legal literature on whether information disclosure incentivizes better performance. For a literature review of profit incentives associated with greener products, which may lead to industry self-regulation and improved performance, see Susan Summers Raines & Aseem Prakash, Leadership Matters: Policy Entrepreneurship in Corporate Environmental Policy Making, 37 Admin. & Soc’y 3, 6–7 (2005).

[86] See, e.g. Erica Gies, Race Is On to Clean Up Hydraulic Fracturing, N.Y. Times (Dec. 4, 2012), http://www.nytimes.com/2012/12/05/business/energy-environment/race-is-on-to-clean-up-hydraulic-fracturing.html?src=recg (describing water as an emerging risk in the industry and how entrepreneurial firms have proposed less toxic fluids that could be more easily recycled at multiple wells).

[87] Green Frac, Chesapeake Energy, http://www.chk.com/environment/drilling-and-production/pages/green-frac.aspx (last visited Nov. 25, 2012).

[88] See James Slutz, President and Managing Dir., Global Energy Strategies, LLC, Presentation to the Asan Institute for Policy Studies (Jan, 11, 2013) (on file with Author) (describing Halliburton’s efforts to limit the number of surface tanks and other equipment needed and to increase their density and describing zero spill technologies such as “Kelly Kan”); Press Release, Halliburton, El Paso and Halliburton Pioneer the First Natural Gas Completion Using All Current Cleansuite™ “Green Technologies” for Hydraulic Fracturing and Water treatment (May 2, 2011), http://www.halliburton.com/public/news/pubsdata/press_release/2011/corpnws_050211_1.html?SRC=ElPasoandHalliburton; Halliburton, Manufacturing Approach to Fracturing Limits Environmental Impact 22 (2006), http://www.halliburton.com/public/pe/contents/Papers_and_Articles/web/A_through_P/FracFactory.pdf (noting techniques such as drilling wells in clusters and installing portable fracturing technologies in order to reduce environmental impact).

[89] See Wiseman, supra note 51.

[90] Bradley C. Karkkainen, “New Governance” In Legal Thought and in the World: Some Splitting as Antidote to Overzealous Lumping, 89 Minn. L. Rev. 471, 473 (2004).

[91] Jody Freeman, Collaborative Governance in the Administrative State, 45 UCLA L. Rev. 1, 22 (1997).

[92] See Dennis D. Hirsch, Project XL and the Special Case: The EPA’s Untold Success Story, 26 Colum. J. Envtl. L. 219, 223–25 (2001).

[93] Freeman, supra note 91, at 22–24.

[94] Freeman, supra note 91, at 50–52.

[95] More investigation into the decisionmaking processes behind agency disclosure rules will be required to determine the extent to which collaborative governance occurred, if at all. Many states engaged in traditional notice and comment rulemaking and held public hearings on proposed rules. See, e.g., Mont. Dep’t of Natural Res. & Conservation Bd. of Oil & Gas, Transcript of Public Hearing (June 23, 2011), http://bogc.dnrc.mt.gov/PDF/Hydraulic%20Fracturing%20Rule%20Hearing06152011.pdf; Mont. Dep’t of Natural Res. & Conservation Bd. of Oil & Gas, Written and E-mailed Public Comments, http://bogc.dnrc.mt.gov/PDF/CombinedComments.pdf; R.R Comm’n of Tex., 16 TAC Chapter 3-Oil and Gas Division, http://www.rrc.state.tx.us/rules/signed-adopt-3-29-Dec13-2011.PDF (showing nine written comments from environmental groups and industry and describing additional comments from a public hearing).

[96] See, e.g. Apache Supports Full Disclosure of Hydraulic Fracturing Information, Apache Corporation, http://www.apachecorp.com/News/Articles/View_Article.aspx?Article.ItemID=2554 (last visited Dec. 10, 2012) (suggesting that FracFocus was “designed to provide easy access by non-technical users”).

[97] See Hydraulic Fracture Stimulation Operations, 37 La. Reg. 3064 (Oct. 20, 2011) (codified at La. Admin. Code tit. 43, pt. XIX, § 118), available at http://www.doa.louisiana.gov/osr/reg/1110/1110.pdf (introducing a rule with disclosure requirements for fracturing chemicals and pressures, indicating that “a review of Office of Conservation policies and regulations associated with the hydraulic fracturing process was conducted by the non-profit, multi-stakeholder organization, STRONGER, Inc. to assess the effectiveness and adequacy of current regulations. Their report . . . recommended some of the changes in this amendment.”); STRONGER, Louisiana Hydraulic Fracturing State Review 14 (2011), available at http://dnr.louisiana.gov/assets/OC/haynesville_shale/071311_stronger_review.pdf (“The review team recommends that reporting should include the identification of materials used, aggregate volumes of fracturing fluids and proppant used, and fracture pressures recorded.”).

[98] See supra text accompanying note 45.

[99] See source cited supra note 39.

[100] See source cited supra note 47.

[101] FracFocus disclosures do not include this information. See, e.g., Hydraulic Fracturing Fluid Product Component Information Disclosure API Number 4212134065, Denton County (Sept. 14, 2011) (on file with author).

[102] See Ground Water Prot. Council, supra note 67.

[103] See, e.g., Nicole Darnall et al., Sponsorship Matters: Assessing Business Participation in Government- and Industry-Sponsored Voluntary Environmental Programs, 20 J. Pub. Admin. Res. & Theory 283, 284 (2009), available at http://mason.gmu.edu/~ndarnall/docs/sponsorship_matters.pdf (describing “voluntary environmental programs” under which “[i]n return for incurring private costs for adopting . . . beyond-compliance policies, organizations can receive benefits such as goodwill from the external stakeholders, enhanced reputation, and improved external relations”); Daniel C. Esty & Andrew S. Winston, Green to Gold: How Smart Companies Use Environmental Strategy to Innovate, Create Value, and Build Competitive Advantage 3 (2006) (explaining that “leading companies have learned to manage environmental risks and costs as closely as they do other risks and costs” and have accordingly reduced “the risk to the whole enterprise”).

[104] Peter A. Appel, Improving Corporate Environmental Performance: Encouraging Sustainable Commerce through Regulatory and Other Governmental Action, (Univ. of Oslo Faculty of Law, Research Paper No. 2011-27, 2011), available at http://papers.ssrn.com/sol3/papers.cfm?abstract_id=1924808.

[105] See Dennis D. Hirsch, Green Business and the Importance of Reflexive Law: What Michael Porter Didn’t Say, 62 Admin. L. Rev. 1063, 1069 (2010) (describing the importance of “reflexive law,” including “legal standards and regulatory policies that push private firms to: (1) internalize social goals (e.g., environmental performance goals) and adopt them as their own, and (2) creatively self-manage their operations so as better to achieve those goals” and providing examples, including requirements for “information disclosure, stakeholder involvement, and planning requirements”).

[106] See id.

[107] See Daniel C. Esty, Environmental Protection in the Information Age, 79 N.Y.U. L. Rev. 115 (2004) (explaining how enhanced technologies for sensing resource use and pollution can both improve decisionmaking and incentivize better industry performance); supra note 52 (identifying other prominent legal scholars who have argued that information incentivizes better performance).

[108] See Raines & Prakash, supra note 85 (summarizing the literature on firms’ “incentives to self-regulate to forestall mandatory regulation”).

[109] See id.

[110] The GWPC, which helped to form FracFocus, has argued against federal regulation. Scott Kell, President, Ground Water Prot. Council, Statement to House Subcommittee on Energy and Mineral Resources (June 4, 2009), available at http://www.dec.ny.gov/docs/materials_minerals_pdf/ogsgeisapp2.pdf (arguing that “[a] one-size-fits-all federal program is not the most effective way to regulate in this area”).

[111] Many of the public demands for regulation of hydraulic fracturing have specifically addressed chemical disclosure. See, e.g., Mont. Dep’t of Natural Res. & Conservation Bd. Of Oil & Gas, Written and E-mailed Public Comments, supra note 95, at 1 (“I want to know what is in the chemicals as they will end up in my food and water.”); id. at 2 (“The chemical information for any fracturing fluids used needs to be easily accessible by the public in a common area such as the Board of Oil and Gas Conservation website.”); id. at 4 (“We feel it is imperative that if there is to be any fracking in our vicinity there is full disclosure of chemicals being used in this process.”).

[112] See supra note 21 and accompanying text.

[113] See supra notes 87–88 and accompanying text.

[114] Karkkainen, supra note 52, at 260–61.

[115] Reporting is in maximum ingredient concentration (% by mass). See supra note 101.

[116] See, e.g., Mike Soraghan, Diesel Still Used to “Frack” Wells, FracFocus Data Show, E&E Publishing, LLC. (Aug. 17, 2012), http://www.eenews.net/public/energywire/2012/08/17/1 (“Diesel fuel has been used to ‘frack’ at least 138 wells in the United States in the past year and a half, according to data filed by drillers with the FracFocus.org registry.”).

[117] See U.S. Gov’t Accountability Office, supra note 10 (concluding that the risks cannot currently be quantified).

[118] See id.