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THE NATURAL GAS INDUSTRY: LESSONS FOR THE FUTURE OF THE

CARBON DIOXIDE CAPTURE AND

STORAGE INDUSTRY

David Schwartz*

INTRODUCTION

The United States is one of the world’s leading producers of two chemi-cally simple but crucially important gases, carbon dioxide (CO2) and natural gas (CH4).1 In terms of growth, the two industries are at opposite ends of the spectrum: the “industry” for capturing, sequestering, and storing CO2 is incipi-ent at best, whereas the natural gas industry is fully developed, having gone through almost a century of development, regulation, and restructuring. Natural gas is an integral part of the U.S. economy, accounting for almost a fifth of U.S. power generation, as well as being the major source of energy for residen-tial heating purposes.2 More impressively, the natural gas industry has an in-credible infrastructure: over 420,000 natural gas wells in the United States alone3 produce 18.5 trillion cubic feet of natural gas4 that is transported

* David Schwartz is a second year law student at Stanford Law School, with a B.A. in International Politics and Economics from Middlebury College, 2004. Before Stanford, David was an Associate Analyst with NERA in White Plains, NY.

1. In 2004, the United States was second only to Russia in natural gas production and first in CO2 emissions. ENERGY INFO. ADMIN., INT’L ENERGY ANNUAL: WORLD CARBON

DIOXIDE EMISSIONS FROM THE CONSUMPTION AND FLARING OF FOSSIL FUELS, 1980-2005

(2005), available at http://www.eia.doe.gov/pub/international/iealf/tableh1co2.xls; ENERGY

INFO. ADMIN., INT'L ENERGY ANNUAL: WORLD DRY NATURAL GAS SUPPLY AND DISPOSITION, 2003 (2004), available at http://www.eia.doe.gov/pub/international/iea2004/table42.xls. (The Energy Information Administration (EIA) is an agency of the U.S. Department of En-ergy).

2. EIA, ANNUAL ENERGY REVIEW 2006, at 50 fig.2.5, 224 fig.8.2a (2006), available at http://www.eia.doe.gov/emeu/aer/pdf/aer.pdf [hereinafter EIA, ANNUAL ENERGY REVIEW

2006]. 3. EIA, Number of Producing Gas and Gas Condensate Wells, http://tonto.eia.doe.gov/

dnav/ng/ng_prod_wells_s1_a.htm (last visited Mar. 5, 2008). 4. EIA, Natural Gas Gross Withdrawals and Production, http://tonto.eia.doe.gov/dnav/


2008] THE NATURAL GAS INDUSTRY 551

through 285,000 miles of pipeline to its various users.5 The United States also imports some 16% of its natural gas, nearly all of it from Canada via pipeline.6

Somewhat ironically, it is the combustion of natural gas, along with all other fossil fuels, that has given rise to the infant industry of CO2 capture and storage (CCS). CCS represents a major tool in the effort to reduce anthropo-genic CO2 emissions into the atmosphere, especially for the United States, which relies on fossil fuels for over 85% of its energy needs.7 And while CCS is only one of a portfolio of measures being considered by policymakers,8 be-cause it can be used for any large point source of CO2, ranging from coal-fired power plants9 to cement production or the iron and steel industry,10 CCS is “the critical enabling technology” that can significantly reduce CO2 emissions while still allowing the United States to rely on coal and other fossil fuels in the near future.11 This is particularly salient for coal, given that the United States pos-sesses the largest recoverable coal reserves on the planet.12 Thus CCS presents what may be the most feasible and broadly applicable method for reducing CO2 outputs that the United States currently possesses in the short- to medium-term.

Many authors and institutions have focused on analyzing CCS because nearly all of the industry’s pieces currently exist or are technologically feasible; all that is left is for someone to put them together.13 It is at this point, however, that difficult questions arise: what will the CCS “industry” look like? Who will own the CO2? How will it be economically feasible? And how will the industry be regulated? While the natural gas industry is not the only analog to CCS,14 a

ng/ng_prod_sum_dcu_NU.S._m.htm (last visited Mar. 5, 2008). 5. NaturalGas.org, Industry and Market Structure, http://www.naturalgas.org/business/

industry.asp (last visited May 11, 2007) [hereinafter NaturalGas.org, Industry] (including both interstate and local distribution companies pipelines).

6. EIA, ANNUAL ENERGY REVIEW 2006, supra note 2, at 186 fig.6.3. 7. Howard J. Herzog, What Future for Carbon Capture and Sequestration?, 35 ENVTL.

SCI. & TECH. 148A, 148A (2001), available at http://sequestration.mit.edu/pdf/EST_ web_article.pdf.

8. INTERGOVERNMENTAL PANEL ON CLIMATE CHANGE, CARBON DIOXIDE CAPTURE AND

STORAGE 2 (2005), available at http://www.ipcc.ch/pdf/special-reports/srccs/srccs_ wholereport.pdf [hereinafter IPCC].

9. See, e.g., MASSACHUSETTS INSTITUTE OF TECHNOLOGY, THE FUTURE OF COAL 43 (2007), available at http://web.mit.edu/coal [hereinafter MIT].

10. IPCC, supra note 8, at 2 tbl.SPM.1. 11. MIT, supra note 9, at x. 12. Id. at 5 fig.2.1. 13. See, e.g., IPCC, supra note 8 at 7 tbl.SPM.2. 14. Other regimes that may provide analogies to the developing CCS industry, espe-

cially related to the underground storage of natural gas, include the Environmental Protec-tion Agency’s Underground Injection Control (UIC) program and state property laws. See generally ENVTL. PROT. AGENCY, USING THE CLASS V EXPERIMENTAL TECHNOLOGY WELL

CLASSIFICATION FOR PILOT GEOLOGIC SEQUESTRATION PROJECTS – THE UIC PROGRAM

GUIDANCE (2007), available at http://www.epa.gov/safewater/uic/pdfs/guide_uic_carbon sequestration_final-03-07.pdf; Elizabeth J. Wilson & Mark A. de Figueiredo, Geologic Car-bon Dioxide Sequestration: An Analysis of Subsurface Property Law, 36 ENVTL. L. INST.


552 STANFORD LAW & POLICY REVIEW [Vol. 19:3

close examination of the industry and its lessons for CCS has yet to occur. This paper seeks to do exactly that: Part I contains a detailed case study of the natu-ral gas industry and its past and present regulation; Part II gives a brief descrip-tion of the CCS industry’s various moving parts; Part III draws lessons from the case study to the CCS industry; and Part V offers some conclusions.

I. THE NATURAL GAS INDUSTRY

A. Present Industry Structure

The natural gas industry is made up of a fairly straightforward structure, starting with natural gas production and processing. Though the discovery and processing of natural gas are deeply involved processes, they are outside the scope of the present analysis.15 Thus the relevant analysis of the natural gas in-dustry begins once the gas has been discovered, processed, pressurized, and ready for transport.

1. Pipelines

Pipelines transfer natural gas from the major production and processing re-gions of the United States to the major consumption areas.16 Figure 1 demon-strates this principle as well as the extent of the natural gas pipeline infrastruc-ture.

Pipeline costs vary widely: factors such as the area’s congestion, terrain (e.g., mountains or rivers), population, and environmental concerns can easily double the cost of pipe per unit length.17 For example, in 2005, new pipeline construction costs ranged from just over $400,000 to over $2.5 million.18 As all gas transported by the pipelines is heavily pressurized, pipelines usually con-tain compressor stations every 40 to 100 miles along a pipeline to recompress the natural gas.19 Moreover, pipeline construction is heavily regulated; in order to build new pipelines the companies must show that the new pipelines serve the public interest, are economically feasible, and do not have significant envi-ronmental impacts.20 Yet even with these costs and regulatory barriers, there

10,114 (2006). 15. For more information, see, e.g., NaturalGas.org, Extraction, http://www.naturalgas.

org/naturalgas/extraction.asp (last visited May 11, 2007). 16. EIA, ADDITIONS TO CAPACITY ON THE U.S. NATURAL GAS PIPELINE NETWORK: 2005,

at 7 (2006), available at http://www.eia.doe.gov/pub/ oil_gas/natural_gas/feature_articles/ 2006/ngpipeline/ngpipeline.pdf [hereinafter EIA, ADDITIONS].

17. IPCC, supra note 8, at 27. 18. EIA, ADDITIONS, supra note 16, at 3 tbl.1 (dividing the estimated cost for new pipe-

line by the length of the pipeline). 19. NaturalGas.org, The Market Under Regulation, http://www.naturalgas.org/

regulation/market.asp (last visited Feb. 25, 2008) [hereinafter, NaturalGas.org, Market]. 20. Id.



are still over 285,000 miles of pipeline in the United States owned by some 160 companies.21

FIGURE 1: United States Underground Natural Gas Storage Facilities in Relationship to the National Natural Gas Transportation Grid, 200522

Beyond pipeline construction, the interstate pipelines’ market operations

are also thoroughly regulated by the Federal Energy Regulatory Commission (FERC) (see Parts I.B-C infra). To begin with, the FERC regulates the pipe-lines’ rates for transportation, insuring that they are “just and reasonable.”23 Prices are usually based on the cost of transportation, which is equal to ex-penses plus a rate of return on the pipeline itself.24 While prices based on mar-ket rates are technically allowable, as of 2004 no pipeline was allowed to

21. EIA, About U.S. Natural Gas Pipelines – Intrastate Natural Gas Pipeline Segment, http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/intrastate.html (last visited Mar. 5, 2008). Of the over 285,000 miles of pipe, some 210,000 miles are interstate pipelines and thus regulated by the Federal Energy Regulatory Commission (FERC); the remaining 86,000 miles of pipe move processed gas intrastate, from producers to local markets and citygates. EIA, About U.S. Natural Gas Pipelines—Estimated Natural Gas Pipeline Mileage in the Lower 48 States, 2006, http://www.eia.doe.gov/pub/oil_gas/ natural_gas/analysis_publications/ngpipeline/mileage.html (last visited Mar. 5, 2008).

22. EIA, U.S. UNDERGROUND NATURAL GAS STORAGE DEVELOPMENTS: 1998-2005, at 2 (2006), available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ ngstorage/ngstorage.pdf [hereinafter EIA, UNDERGROUND STORAGE].

23. 18 C.F.R. § 154.202(a)(1)(vi) (2007). 24. JAMES TOBIN, DEP’T OF ENERGY, NATURAL GAS MARKET CENTERS AND HUBS: A

2003 UPDATE (2003), available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/ feature_articles/2003/market_hubs/mkthubs03.pdf.



charge such prices, due to the FERC’s fears of pipelines’ ability to charge above-market prices (see Part I.B infra).25

The FERC has also required the pipelines to provide “open access” to all firms, making the pipelines common carriers.26 Irrespective of whether the cus-tomer requiring the pipeline’s services (a “shipper”) actually purchased gas from the pipeline company, the pipeline must transport the shipper’s natural gas.27 Additionally, the FERC requires pipelines to make available consider-able amounts of information about their tariff schedule and available capacity, usually via an electronic format.28 The combination of these two requirements has resulted in the deep integration of the national natural gas market: The ad-ditional capacity, combined with the ability for anyone to use it, has given the natural gas market a flexibility that allows shippers to move natural gas across the country to meet demand on a moment’s notice.29 Pipelines are thus a heav-ily regulated portion of the natural gas industry, and while this regulation un-doubtedly burdens expanding pipeline capacity, it has also given the natural gas industry as a whole unprecedented flexibility and integration.

2. Market Centers

The advent of pipelines as common carriers, created by the industry re-structuring in the 1990s, has resulted in a series of market centers located at “hubs” of pipelines. These market centers provide a wide array of crucial ser-vices for the natural gas industry, from storing the natural gas (see below), to physically moving the gas between pipelines, to transferring title between pro-ducers and consumers.30 Presently, transferring and transporting gas between shippers and consumers remain the market centers’ most important function.31 The price the centers can charge for those various services depends on whether those services are regulated by the FERC.32 For example, a center can only charge the cost of service for transporting gas along an interstate pipeline, as

25. Michael J. Doane et al., Evaluating and Enhancing Competition in the Interstate Natural Gas Transportation Industry, 44 NAT. RESOURCES J. 761, 763-64 (2004).

26. Regulation of intrastate pipeline is done at the state level and varies widely. For example, in 2005 eight states had “unbundled” their pipelines, see infra Part II.C; another fourteen were in the process of unbundling; and the remainder had not unbundled their pipe-lines. See, e.g., id. at 762; EIA, Natural Gas Residential Choice Programs, http://www.eia.doe.gov/oil_gas/natural_gas/restructure/historical/2005/restructure.html (last viewed Mar. 5, 2008).

27. Doane et al., supra note 25, at 762. 28. Id. 29. Id. at 768 (noting that the price movements of the natural gas market have become

highly correlated, even if the price of natural gas varies by producing region); Natural-Gas.org, The History of Regulation, http://www.naturalgas.org/regulation/history.asp (last visited May 13, 2007) [hereinafter NaturalGas.org, History].

30. TOBIN, supra note 24. 31. Id. 32. Id.



the FERC mandates the pipelines’ rates, but can charge market-based rates for services such as title transfer or parking (i.e. short-term storage).33

The firms that own such market centers, called gas marketers, are often specialized firms involved in a variety of markets, the most notorious of which was, until recently, Enron.34 The development of market centers has greatly enhanced the integration of the natural gas industry. Besides creating ideal lo-cations for spot and future markets (the New York Mercantile Exchange deliv-ery point for natural gas futures is the Henry Hub in Louisiana), the market centers have also spurred increased connections between the pipelines them-selves.35 These two trends have also greatly contributed to the natural gas in-dustry’s present flexibility: not only can buyers and sellers easily discover the best price for their needs, but the market centers’ ability to store and move gas allows market participants to move gas around the country at a moment’s no-tice, or hold onto the gas until a better price shows up.36 Market hubs are thus a recent development in the natural gas industry, but are nonetheless a crucial one.

3. Storage

The market centers would not exist without the ability to store gas over a long period of time; indeed, more than two-thirds of the U.S. market centers have some form of access to storage.37 However, market centers are not the only entities in the natural gas industry that own storage: pipeline companies, shippers, producers, and local distribution companies all own storage facilities for various purposes.38 Today, the United States has nearly 400 natural gas storage sites, holding an estimated 3600 billion cubic feet of available stor-age,39 or nearly 61,750 thousand metric tons of natural gas.

Natural gas storage facilities come in one of three forms: depleted natural gas reservoirs, aquifers, and salt caverns.40 Each of the facilities has relative

33. Id. 34. NaturalGas.org, Marketing, http://www.naturalgas.org/naturalgas/marketing.asp

(last viewed May 13, 2007). 35. TOBIN, supra note 24. 36. Id. 37. Id. For this analysis, storage does not include linepack, which is the short-term

storage of natural gas by temporarily increasing the compression of the natural gas beyond the pipeline’s capacity. Id. at 12 n.16.

38. EIA, ESTIMATES OF MAXIMUM UNDERGROUND WORKING GAS STORAGE CAPACITY

IN THE UNITED STATES 1 (2006), available at http://www.eia.doe.gov/pub/oil_gas/ natural_gas/analysis_publications/ngcapacity/ngcapacity.pdf [hereinafter EIA, ESTIMATES].

39. Id. at 1, 4. This storage is “working gas,” which is defined as natural gas stored with the intention of being withdrawn in the near future, as compared to “base gas,” which exists in all natural gas storage facilities and is used to maintain the necessary pressure in order to withdraw the working gas.

40. NaturalGas.org, Storage of Natural Gas, http://www.naturalgas.org/naturalgas/



advantages and disadvantages. Salt caverns can hold less natural gas overall,41 but have greater deliverability rates, as measured by the amount of gas able to be withdrawn per day.42 In contrast, the depleted natural gas reservoirs have greater capacity and are cheaper and more convenient than salt caverns, but have less deliverability.43 Aquifers are in general the least desirable form of natural gas storage, as they are the most expensive option, and such storage is only used when there are no alternatives.44 As Figure 1 supra shows, most high-deliverability salt cavern storage exists near the major productions areas like the Southwest and the Gulf Coast, while the larger depleted reservoirs are located closer to the main areas of consumption like the Midwest and North-east.

Such storage exists to serve two primary purposes: to meet seasonal and short-term demands. For seasonal demands, aquifers and depleted reservoirs hold natural gas during the summer months when natural gas demand is low, releasing the gas into the pipeline during the winter when natural gas demand is high due to residential heating demands.45 For short-term or peak demands, salt-caverns hold natural gas that can be injected into the pipeline system on very short or no notice.46 In general, natural gas is never stored for longer than a season; it is operationally improper to let natural gas sit in storage, as it will naturally move toward low-pressure areas of the storage facility, eventually be-ing converted into base gas and thus lost.47 In meeting such demands, the eco-nomics of storage vary by the ownership of the storage facility. For example, the ownership of the natural gas in storage depends on the entity that owns the storage facility. In many cases, the gas stored inside the facility is not owned by the storage facility owner, but instead owned by the various shippers and pro-ducers who own the rights to the storage capacity.48 Like the pipelines, storage facilities are required to give open access to any customers, thus a wide variety of parties can own a storage facility’s gas at any one moment in time.49 On the whole, most natural gas in storage is owned by parties other than the facility owner.

More generally, any storage facility that is integrated into a pipeline sys-

storage.asp (last visited May 13, 2007) [hereinafter NaturalGas.org, Storage]. 41. Id. 42. EIA, ESTIMATES, supra note 38, at 4. 43. See, e.g., FERC, CURRENT STATE OF AND ISSUES CONCERNING UNDERGROUND

NATURAL GAS STORAGE 1, 18 (2004), available at http://www.ferc.gov/EventCalendar/ Files/20041020081349-final-gs-report.pdf; NaturalGas.org, Storage, supra note 40.

44. NaturalGas.org, Storage, supra note 40. 45. Id. 46. EIA, UNDERGROUND STORAGE, supra note 17, at 2. 47. FERC, supra note 43, at 6. 48. EIA, ESTIMATES, supra note 38, at 2. 49. See, e.g., id. at 1. However, some gas inside storage is owned by the storage own-

ers. For example, pipelines are allowed to hold back a certain amount of storage space in or-der to balance the natural gas load and manage supply.



tem, whether owned independently or by a pipeline, is also heavily regulated by the FERC. In order to be built, the FERC must determine that the storage is “required by the present or future public convenience and necessity,” as well as economically feasible.50 Such regulation has a direct impact on the rate of re-turn for a storage facility: the expected returns for a storage project not covered by the FERC (“non-jurisdictional”) are usually 20%, whereas for projects under FERC regulation (“jurisdictional”), the expected returns range from 12-15%.51 However, unlike the pipelines the FERC has allowed some storage facilities to charge market-based rates rather than simply cost of service.52 These market-based rates have recently been seen by the natural gas industry as crucial to a storage facility’s financial success: without FERC approval to charge market-based rates, several proposed facilities have been delayed or cancelled, based on fears that the cost-of-service rates would not create adequate profits.53 Thus natural gas storage plays a crucial role in the natural gas industry, though FERC regulation greatly affects whether a storage facility can even exist, and whether it will be profitable. 54

The final step in the natural gas industry involves distributing the gas to the individual purchasers by local distribution companies (LDCs), which is often the costliest step in the entire process.55 However, this distribution step is out-side the scope of this analysis, especially given that individual LDCs take on a variety of forms due to specific state regulation. Thus, the natural gas industry thus has a fairly straightforward market chain: natural gas is extracted from wells, processed, shipped along pipelines, usually stored for some period of time, transferred again to the LDCs, and finally delivered to the end-user. Gas marketers can be involved in nearly every step of the process, from taking ownership of the gas stream as soon as it leaves the well to selling directly to LDCs.56 The economic interactions between these various moving parts are fairly complex, especially with the advent of gas marketers; however, as will be explored in detail below, the evolution of natural gas regulation has forced the industry, and especially the pipelines, to undergo several transformations.

B. History of Natural Gas Regulation

Almost from its very inception, the natural gas industry was regulated by

50. 18 C.F.R. § 157.6(b)(2) & (8) (2007). 51. FERC, supra note 43, at 18. 52. Doane et al., supra note 25, at 764 n.11. 53. FERC, supra note 43, at 3, 15. 54. Such profitability also greatly depends on the local characteristics of the storage

facility and its intended role: high-deliverability storage such as salt caverns can cost nearly twice as much to develop as seasonally-focused depleted natural gas reservoirs. Id. at 18.

55. See, e.g., NaturalGas.org, Natural Gas Distribution, http://www.naturalgas.org/ naturalgas/distribution.asp (last visited May 13, 2007).

56. NaturalGas.org, Industry, supra note 5.



some form of government. However, until the 1920s and 1930s, natural gas was traditionally seen as a nuisance associated with oil drilling; most natural gas was flared or vented from oil wells.57 Only after new technological ad-vances in the science of pipe-welding could shippers transport natural gas from the production centers to markets.58 Once natural gas could be shipped, state and federal regulators recognized the market power of the pipelines, which were in “both a monopsony and a monopoly position.”59 Pipelines were mo-nopsonists in that a pipeline was the only buyer that natural gas producers had access to at any given field.60 Pipelines were also monopolists in that they were the only seller and transporter of natural gas available to an end-user, whether that use was an LDC or an industrial company.61 The pipelines’ powerful posi-tion, combined with the fact that the cost of the necessary infrastructure created high barriers to entry, made pipeline companies (as well as LDCs) ripe for state regulation.62

However, because natural gas often had to be transported across state lines, a regulatory gap developed once the natural gas left the state.63 While states were allowed to regulate intrastate gas,64 any regulation of interstate gas was struck down by the Supreme Court as a violation of the Dormant Commerce Clause.65 This constitutional objection was laid to rest when Congress passed the Natural Gas Act (NGA) in 1938.66 The NGA was based on a 1935 Federal Trade Commission (FTC) report outlining the monopoly and monopsony as-pects described above, coming to the same conclusion that the natural gas pipe-line industry was a natural monopoly, and concluding that the pipelines should be regulated by the federal government.67 While the theory of “natural monop-oly” has since come under criticism, the basic idea that certain industries are best served (i.e., face a lower average cost) by a single, regulated monopolist rather than by several, competing firms seemed to apply to the natural gas pipe-

57. Suedeen G. Kelly, Natural Gas, in ENERGY LAW AND POLICY FOR THE 21ST

CENTURY 8-1, 8-16 (Energy Law Group eds., 2000). 58. Id. at 8-16, 8-17; David V. Bryce, Note, Pipeline Gathering in an Unbundled

World: How FERC’s Response to “Spin Down” Threatens Competition in the Natural Gas Industry, 89 MINN. L. REV. 537, 541 n.28 (2004) (noting that previous pipelines had been constructed with screws; given that natural gas is highly pressurized, transport often resulted in a 40% loss due to leakage); NaturalGas.org, History, supra note 29.

59. Kelly, supra note 57, at 8-17. 60. Id. 61. Id. 62. Id. 63. NaturalGas.org, History, supra note 29. 64. Pa. Gas Co. v. Pub. Serv. Comm’n of N.Y., 252 U.S. 23 (1920); Pub. Utilities

Comm’n v. Landon, 249 U.S. 236, vacated and modified, 249 U.S. 590 (1919). 65. Mo. ex rel. Barrett v. Kan. Natural Gas Co., 265 U.S. 298, 309-10 (1924). 66. The NGA was held to be constitutional in Fed. Powers Comm’n v. Natural Gas

Pipeline Co., 315 U.S. 575 (1942). 67. Bryce, supra note 58, at 543; Kelly, supra note 57, at 8-19.



line industry.68 The NGA, still in existence today, created the Federal Power Commission

(FPC), which was charged to insure that both the prices pipelines charged for transportation and for the gas itself were “just and reasonable.”69 Such price regulation was necessary because of the pipelines’ near-complete market con-trol. The NGA regulated the pipelines by giving them certificates of public convenience and necessity to provide exclusive gas and transportation services to a particular geographic area, essentially handing the pipelines captive mar-kets.70 Natural gas markets were captive because the pipeline provided bundled services to the end-user, who thus paid a single price for the gathering, process-ing, storing, transporting, and marketing of the natural gas.71 Indeed, under the FPC regime pipelines owned nearly all the gas that they transported, demon-strating the extent of the natural gas industry’s vertical integration in the 1930s and 1940s.72

In exchange for these captive markets, pipelines had to provide non-discriminatory service, which was insured by the FPC requirement that pipe-lines file their rates and conditions of services with the FPC (and later the FERC).73 Moreover, in a further effort to insure stability of supply and limit financial risk, prior to the approval of a new pipeline (and later, new storage facilities integrated into the pipelines), the FPC required pipelines to enter into long-term contracts with gas producers, typically anywhere from twenty years to the entire life of the well, which can last as long as forty years.74 This effort only further solidified the highly-structured natural gas industry, which the pipelines expanded and dominated.75 The early history of the natural gas indus-try is thus one of strong vertical integration by the pipelines, which was rein-forced by FPC regulations.

However, the NGA was specifically limited to exempt gas gathering and production from the FPC’s jurisdiction.76 There were two primary justifications for this limitation. First, production and gathering most often occurs entirely within states, and thus subject to state regulation; there was thus no “regulatory gap” that needed to be filled by federal legislation.77 Second, production and gathering, unlike pipelines, is characterized by robust competition.78 But in

68. Bryce, supra note 58, at 543. 69. 15 U.S.C. § 717c(a) (2007); Kelly, supra note 57, at 8-20. 70. Bryce, supra note 58, at 546; Kelly, supra note 57, at 8-20. 71. Bryce, supra note 58, at 545. 72. Id. 73. Id. 74. Kelly, supra note 57, at 8-20. 75. Id. 76. 15 U.S.C. § 717(b) (2007). 77. Bryce, supra note 58, at 547. 78. Id.; see generally Kelly, supra note 57, at 8-21 (noting that natural gas production

was not done by monopolists).



1954 the Supreme Court greatly expanded the FPC’s power, ruling that a pro-ducer selling gas for resale in interstate commerce fell within the FPC’s juris-diction.79 Suddenly, the FPC had to regulate the prices of any natural gas com-pany that sold gas for resale to an interstate pipeline, rather than regulating only the pipelines.80 The massive number of newly regulated entities crushed the FPC: when it attempted to analyze “reasonable” producer rates on a case-by-case basis, within a decade the FPC had a backlog over eighty-three years long.81

The FPC responded first by setting regional, and then national rates for natural gas.82 However, the FPC differentiated between several types of gas. Only gas that had been previously discovered, called “old” gas, was subject to the low national price ceilings, whereas “new” gas was subject to much higher prices, in order to encourage exploration.83 Moreover, the FPC could still not regulate any natural gas that was sold for purely intrastate consumption, and thus intrastate gas was sold for higher prices.84 The result was that producers were incentivized to only sell to intrastate customers, leading to shortages in the interstate natural gas market.85 Nonetheless, because intrastate gas prices tracked the regulated interstate prices, albeit at a higher level, the price for natural gas was on the whole artificially low, creating predictable economic outcomes: natural gas demand was high, yet supply was low due to decreased investment in new production.86 These price differentials and economic results were further exacerbated by the 1973 OPEC oil embargoes and record-cold winters in the latter half of the 1970s, causing consumers to demand interstate natural gas that simply did not exist.87 The various price discrepancies led to untenable situations. During the mid-1970s, schools in Midwestern consuming states were forced to close due to natural gas shortages (and thus had no heat during the winter) while producing states simultaneously felt no shortage at all, given that intrastate sales of gas were relatively plentiful.88

As a result of these problems, Congress passed the Natural Gas Policy Act of 1978 (NGPA).89 The NGPA replaced the FPC with the FERC, raised the maximum prices for natural gas, and set out an eight-year plan to deregulate gas prices, starting with wellhead prices.90 The NGPA strove to accomplish the

79. Phillips Petroleum v. Wisconsin, 347 U.S. 672, 685 (1954). 80. Kelly, supra note 57, at 8-20, 8-21. 81. Id. at 8-21. 82. Id. 83. Id. 84. Id. 85. Id. at 8-22; Bryce, supra note 58, at 549. 86. Kelly, supra note 57, at 8-22. 87. Id. at 8-22, 8-23. 88. NaturalGas.org, History, supra note 29. 89. Bryce, supra note 58, at 549. 90. Id.; Kelly, supra note 57, at 8-23. The “wellhead” price is the price natural gas



latter goal by extending natural gas price controls to intrastate gas markets, with the eventual goal of deregulating the gas prices altogether.91 Yet the price increases had similarly predictable economic effects: natural gas production in-creased in response to the higher wellhead prices, while at the same time natu-ral gas demand dropped.92 Once again, international problems exacerbated the economic shifts: a drop in oil prices, resulting from a lack of united action from OPEC in the early 1980s, led customers to switch to cheaper oil, as some 23% to 35% of U.S. natural gas consumers could do.93 By the 1980s, instead of natural gas shortages, the industry now faced a glut.

Moreover, despite the regulatory changes, pipelines still remained locked in to long-term contracts, many of which had two highly significant clauses. First, the contracts had automatic price escalation clauses, reflecting the NGPA’s higher natural gas prices. Second, the contracts required the pipelines to pay for all of the gas they contracted for, even if they did not physically take or transport it. These “take-or-pay” clauses forced many pipelines nearly to bankruptcy as they were forced to pay high prices for gas they could not sell.94 Thus the natural gas regulation was unable to keep up with the shifting market-place and international shocks; the federal government’s responses only swung the pendulum too far in the other direction.

The FERC’s response to the pipeline’s financial crisis was new forms of deregulation. First starting in 1985 with Order No. 436, the FERC gave incen-tives to the pipelines to provide open access to all customers.95 Such open ac-cess was crucial: it gave the sellers of gas the chance to deal directly with the many consumers of gas, such as LDCs, rather than the pipelines.96 The FERC’s incentives included easier certification for new services or facilities, as well as converting pipelines’ take-or-pay contracts into transportation-only contracts.97 The deregulation was an immediate success, and by 1992 some 79% of gas transported by pipelines consisted of competitors’ natural gas.98 Nonetheless, pipelines still had their own affiliates, and gave preferential service to those who purchased gas from their production and sales services.99 The FERC’s re-sponse to these continuing problems, as well as the incomplete take-up of open access, was to pass Order No. 636, which completed the final restructuring of

processors pay for raw natural gas straight from the well. Naturalgas.org, Processing Natural Gas, http://www.naturalgas.org/naturalgas/processing_ng.asp (last visited May 11, 2007).

91. Kelly, supra note 57, at 8-23. 92. Id. 93. Id. at 8-24. 94. Id. 95. Id. at 8-25. 96. Id. 97. Id. 98. Harvey Reiter, The Contrasting Policies of the FCC and FERC Regarding the Im-

portance of Open Transmission Networks in Downstream Competitive Markets, 57 FED. COMM. L.J. 243, 253 (2005).

99. Id. at 254.



the natural gas industry, and today remains the current regulatory regime.100 Thus, the history of natural gas regulation is one characterized by an early mo-nopoly that was encouraged but regulated, first by the states and then by the federal government. However, as natural gas grew in importance, and the United States became more susceptible to international influences, regulation could not keep up, and thus the solution was deregulation.

C. Current State of Natural Gas Regulation

FERC Order No. 636 is the present regulatory regime for the natural gas industry, solidifying a number of growing trends in the natural gas industry, but ending its vertical integration. Essentially, Order 636 made mandatory what Order 436 made voluntary.101 To begin with, Order 636 mandated that pipe-lines allow any customer to use their transportation services on equal terms.102 The FERC requires all pipelines to submit their rates and terms of service for transportation, in order to insure that the pipelines are in fact providing equal terms.103 Second, and most importantly, the FERC mandated that pipelines un-bundle their services: pipelines could no longer offer to purchase and transport natural gas for any customer in the same transaction.104 While pipeline compa-nies can still sell natural gas at market prices, their sales and transportation di-visions must be strictly separated, and the pipeline division cannot provide any services to its sales division that it does not provide to other, third-party ship-pers.105 Order 636 caused most pipelines to abandon their sales businesses or spin them off as arms-length affiliates, since they had to face regulation while their independent competitors did not; today most sales are made by independ-ent sellers or gas marketers.106 For similar reasons, the open-access require-ments also forced pipelines to spin-off their gathering and production facilities: the pipelines’ gathering and production facilities were regulated by the FERC, but now that independent, third party shippers had equal access to the pipe-lines’ services, those shippers could sell to customers at lower, unregulated prices.107 Today, pipelines are common carriers for all shippers, having been required by law to end their vertical integration.

Order 636 had other, far-reaching effects as well. As stated above, the FERC now requires pipelines to post electronically what excess capacity they have available, allowing shippers to see how they can ship their gas.108 This

100. Kelly, supra note 57, at 8-25. 101. NaturalGas.org, Industry, supra note 5. 102. Kelly, supra note 57, at 8-26. 103. Id.; NaturalGas.org, Market, supra note 20. 104. Reiter, supra note 98, at 254. 105. Kelly, supra note 57, at 8-26; Reiter, supra note 98, at 254. 106. Kelly, supra note 57, at 8-26; NaturalGas.org, History, supra note 29. 107. Bryce, supra note 58, at 552. 108. NaturalGas.org, History, supra note 29.



excess capacity is made available when holders of the capacity release it on a secondary market; such excess capacity can then be purchased for any price up to the maximum rate paid by the releasing shipper.109 As a result, shippers are increasingly able to obtain short-term transportation at a moment’s notice.110 The FERC also requires the pipelines to provide such short-term notice service to the point that pipelines must make capacity available to LDCs without any notice.111 Such “no-notice” service is available for LDCs to meet their supply needs on peak days without incurring financial penalties.112 Order 636 thus so-lidified the changing structure of the natural gas market; this restructuring ended the pipelines’ market dominance over the natural gas industry, forcing them to unbundle and providing the industry with much-needed flexibility.

While pipeline rates continue to be regulated by the FERC, the price of gas itself is almost completely unregulated.113 Reinforcing the wellhead decontrol Congress had pursued in the NGPA, in 1989 Congress passed the Natural Gas Wellhead Decontrol Act (NGWDA), eliminating all federal price controls on wellhead prices.114 The NGWDA lists a number of “first sales” of natural gas that are free of federal regulation, including sales to a pipeline, LDC, or end-user.115 Notably, sales by pipelines and LDCs are not considered “first sales,” and thus are still regulated by the FERC.116 However, the NGWDA does not distinguish between intrastate and interstate gas; all first sales of gas are thus unregulated by the federal government, which also preempts the states from regulating intrastate gas prices.117 The current state of natural gas industry regulation thus presents contrasting regulatory regimes: while the pipelines themselves, the rates they charge, and their business activities are heavily regu-lated, the price of natural gas itself is not.

II. THE CO2 CAPTURE AND SEQUESTRATION (CCS) INDUSTRY

The CCS industry exists only in theory, as an option that the United States will likely follow as it deals with its CO2 emissions in the coming years.118

109. Kelly, supra note 57, at 8-26. 110. Doane et al., supra note 25, at 766. 111. NaturalGas.org, History, supra note 29. 112. Id. The FERC implemented this no-notice requirement to allay the LDCs’ fears

that the industry restructuring would affect reliability of service. 113. Kelly, supra note 57, at 8-26. 114. NaturalGas.org, History, supra note 29. 115. Id. 116. Id. 117. Transcont’l Gas Pipeline Corp. v. Miss. Oil & Gas Board, 474 U.S. 409, 425

(1986); see generally Kelly, supra note 57, at 8-18, 8-26 (states can still regulate somewhat how pipelines can take natural gas from producers, for example by using “common pur-chaser” or “prorationing” statutes).

118. See, e.g., Jean-Marie Martin-Amouroux, Challenges and Constraints for Energy Supply: The Coal Hard Facts, in BRINGING DEVELOPING COUNTRIES INTO THE ENERGY



Nonetheless, some of the moving parts of the CCS “industry” (for lack of a bet-ter term) are already apparent; indeed, all of the theoretical technological re-quirements already exist.119 Moreover, the United States currently has a small CO2 industry: more than 1600 miles of pipeline exist transport some 50 MtCO2 a year from natural sources to be used in enhanced oil recovery operations (EOR) in Texas.120 Nonetheless, the scale required for a U.S. CCS industry is on a level far above any current capacities: 2005 U.S. CO2 emissions from power plants alone totaled over 2.5 million MtCO2,

121 or 50,000 times the pre-sent U.S. CO2 pipeline capacity.122 Therefore, since the CCS industry will be qualitatively different than the current U.S. CO2 industry, a brief outline of what the CCS industry could look like is instrumental in understanding the les-sons the natural gas industry can teach.

In terms of infrastructure, the CCS industry will likely be made up of four parts: capture, compression, transportation, and storage.123 Capture will most likely occur at the point of emission; while an entire gas stream could con-ceivably be transported, and even injected underground as a whole (that is, without the CO2 separated from the other emissions), the costs of this approach have been judged to be impractical.124 Capture of CO2 from emissions gener-ated from combustion of a primary fossil fuel (e.g., coal, natural gas, or oil), can occur in one of three ways: post-combustion, pre-combustion, or oxyfuel combustion.125 Each method of capture has its advantage: for example, post-combustion is best suited for existing boilers with low SO2 emissions, whereas oxyfuel is best suited for existing boilers without any SO2 and NOx controls, whereas pre-combustion is best suited for newer plants configured to run on H2, the other substance produced from the chemical reactions associated with pre-combustion technologies.126 Such technologies require their own energy inputs in order to function, and thus adding carbon capture to an existing power plant would raise energy needs by 10% to 40%, depending on the method

EQUATION 19 (Michel Colombier & Jacques Loup eds., 2006) (noting that the United States is the only country that meets three conditions that are highly favorable to the development of CCS).

119. IPCC, supra note 8, at 2 tbl.SPM.2. 120. Id. at 181. 121. EIA, ELECTRIC POWER ANNUAL 2005, at 40 tbl.5.1 (2005), available at

http://www.eia.doe.gov/cneaf/electricity/epa/epa.pdf. 122. Today, the yearly U.S. production of CO2 is equivalent to three times the weight

and one-third the annual volume of the U.S. natural gas pipeline system. MIT, supra note 9, at ix.

123. Sally M. Benson, Carbon Dioxide Capture and Storage in Underground Geologic Formations, in THE 10-50 SOLUTION: TECHNOLOGIES AND POLICIES FOR A LOW-CARBON

FUTURE 2 (Pew Center for Global Climate Change ed., 2004). 124. IPCC, supra note 8, at 22. 125. Id. 126. Dale Simbeck, Contributing Paper: CO2 Capture Economics, in THE 10-50

SOLUTION: TECHNOLOGIES AND POLICIES FOR A LOW-CARBON FUTURE, supra note 123, at 1-3.



adopted.127 However, once applied, such technologies can capture between 80% to 90% of CO2 generated by power plants,128 which in 2005 made up over 38% of total U.S. CO2 emissions.129 While CCS technologies are not limited to power plants, such plants have seen the first applications of such technolo-gies.130 Thus there are various capture options suited specifically to an emis-sion source’s particular construction and controls.

In terms of economics, the costs of CCS technologies depend greatly on whether such plants are retrofitted or are newly built with integrated CCS tech-nology. For old plants, installing CCS technologies will increase the cost of producing a megawatt hour (MWh) of electricity by $41 to $49, resulting in the cost of avoiding a ton of CO2 ranging from $55 to $165.131 For new plants, the cost increase of a MWh are somewhat lower, increasing by $16 to $36 per MWh; however, the cost of a ton of CO2 avoided is slightly higher, ranging from $67 to $190.132 The differences occur because the older plants have al-ready paid off their capital costs, and thus the costs to generate electricity are lower, while the costs to add CCS technologies are higher.133 Most analyses show that the costs for the capture of CO2 will be the largest component of a CCS system.134 Thus the CCS technology will likely be applied at the source of the emissions and will impose substantial costs, both in the price of electricity and the efficiency of the emission source.

Once the CO2 is separated from the emissions, it must be compressed and potentially filtered. Such compression technologies are already well-developed for the current CO2 industry;135 today such gas is usually compressed to about 11 to 14 MPa before it is shipped.136 However, there has been little discussion as to where such compression and filtration will occur. While on-site compres-sion and filtration could be more convenient, it may be inefficient to require a large number of entities to undergo the same type of filtration and compression procedures when a single compression and filtration plant could conduct these

127. IPCC, supra note 8, at 22. Note that this figure also includes the energy needed for compression.

128. Id. 129. EIA, ANNUAL ENERGY OUTLOOK 2007 WITH PROJECTIONS TO 2030, at 101 fig.92

(2007), http://www.eia.doe.gov/oiaf/archive/aeo07/pdf/0383(2007).pdf; EIA, TABLE 18: CARBON DIOXIDE EMISSIONS BY SECTOR AND SOURCE, http://www.eia.doe.gov/oiaf/ archive/aeo07/pdf/aeotab_18.pdf (dividing total electric power CO2 emissions by total U.S. emissions).

130. See, e.g., MIT, supra note 9, at 48 tbl.4.1. 131. Simbeck, supra note 126, at 4. Note that the IPCC gives different numbers, with

larger ranges for the costs of a ton of CO2 avoided, but also include the cost of compression. IPCC, supra note 8, at 10 tbls.SPM.4 & SPM.5.

132. Simbeck, supra note 126, at 3. 133. See id. 134. Benson, supra note 123, at 13 (noting that separation and compression account for

over 75% of CCS costs); IPCC, supra note 8, at 9-10. 135. Benson, supra note 123, at 3. 136. IPCC, supra note 8, at 24.



procedures for all local emissions sources. On the other hand, transporting such emissions may be costly, unnecessary (see below), and too difficult for a single processing plant, given the wide variety of emission sources that may be equipped with such CCS technology (e.g., the composition of the CO2 and as-sociated chemicals emitted from a cement factory may need to be treated dif-ferently than the CO2 emissions from a natural gas power plant). Such discus-sions on the use of compression and filtration have yet to occur in the context of the CCS industry.

The CO2, now compressed and filtered, must be transported to storage. In the beginning, this step in the CCS industry may not be substantial, if it exists at all outside of an individual firm. This is because of co-location: Several ana-lysts predict that most new power stations will explicitly take into account the location of CO2 storage and accordingly, build as close as possible to the stor-age.137 However, this may not be possible or efficient in all cases.138 In such cases, pipelines may need to be built in order to transport the CO2 from the emitter to storage. As noted above, such CO2 pipeline technology is already mature, as compared to some of the capture technology (e.g., pre-combustion technology).139

From an economic perspective, estimates of the cost of a pipeline range from $1 to $8 per ton of CO2,140 though as stated supra in Part I.A.1, such costs are highly dependent on the physical and population characteristics of the areas in which the pipelines would be laid.141 Additional costs could also be incurred as the pipelines grow, for example for recompression stations,142 as well as from corrosion if the transported CO2 contains water.143 The costs per ton of CO2 do decrease as the amount of CO2 shipped through the pipelines in-creases.144 Moreover, in some cases it may be economical to transport CO2 via ship, especially if the distances are greater than 1000km (621mi).145 However, because of the inchoate nature of the CCS industry, no analysis to date has ex-amined the costs associated with regulatory barriers, which could be signifi-cant.146 Thus, in the early stages of the CCS industry, the need for pipelines

137. See, e.g., Benson, supra note 123, at 8; IPCC, supra note 8, at 7-8 figs.SPM.6a & SPM.6b (noting that many large point sources of CO2 emissions are located within 300km (187mi) of many prospective storage locations).

138. See, e.g., FERC, supra note 43, at 3 (noting that the geology in parts of the North-east are not suitable for underground natural gas storage).

139. IPCC, supra note 8, at 22. 140. Id. at 27 (assumed for 250km (155mi) of pipeline). 141. Id.; MIT, supra note 9, at 58; see also Part II.A.1 supra. 142. IPCC, supra note 8, at 27 (assuming that such costs would be relatively trivial and

thus not accounted for). 143. Id. 144. Id. at 27 fig.TS.5. 145. Id. at 28 fig.TS.6. 146. Cf. MIT, supra note 9, at 56 (arguing that “[b]uilding a regulatory framework for

CCS should be considered a high priority item,” as the lack of such a framework increases



may not be great, but if pipelines are needed, the costs could vary significantly. The final aspect of the CCS industry is the storage of the CO2. Unlike the

previous two aspects of the CCS industry, the storage of CO2 has received con-siderable attention from a variety of sources; indeed, eleven CO2 storage pro-jects are already planned or underway.147 Such attention has been focused on storage because storage is the most necessary component of the CCS industry. It is undeniable that the needs for storage are several orders of magnitude be-yond what is currently available for natural gas. In 2005 alone, U.S. electric plants produced over 2.5 billion metric tons of CO2, equal to almost 147 billion cubic feet of gas; presently the entire U.S. natural gas storage system has a working gas capacity of around 3600 billion cubic feet.148 Additionally, the CO2 will have to be stored underground for an extended period of time. Though it is unclear exactly how long the CO2 needs to be stored, estimates range from at least several hundred years to permanently.149

Nonetheless, the potential exists for successful CO2 storage, on the scale required for a working CCS industry. First, the emitted CO2 would likely be injected at such a depth or pressure as to be in a liquid state, thus greatly in-creasing the amount of CO2 that a given storage facility could accommodate.150 Second, world CO2 storage facilities have a huge capacity. It is estimated that the United States alone has forty to fifty years worth of CO2 storage capacity at today’s emission rates.151 Third, the technology for injecting CO2 is currently well-developed, as it is commonly used in EOR operations.152 Finally, analyses show that the level of CO2 stored over time will experience very small amounts of leakage; it is very likely that storage sites will experience less than 1% loss of CO2 in 100 years and likely that the sites will experience the same loss in 1000 years.153 Indeed, over a long period of time, the CO2 will eventually dis-solve into or be absorbed by the storage facility itself.154 Thus while there has been attention paid to this portion of the CCS industry, there remain significant challenges to the storage of CO2.

However, the economics behind the storage industry are much more com-plicated. The costs of the storage are relatively straightforward: the cost of stor-age plus monitoring ranges from $0.60 to $1.10 per ton of CO2 injected.155 Given the industry experience in injecting and storing gases underground,

the costs of initiating large-scale CCS projects and deployment). 147. IPCC, supra note 8, at 30 tbl.TS.5. 148. EIA, ESTIMATES, supra note 38, at 4. 149. Benson, supra note 123, at 12. 150. See, e.g., Wilson & Figueiredo, supra note 14, at 10,115. 151. Benson, supra note 123, at 7. 152. Id. at 4; IPCC, supra note 8, at 7 tbl.SPM.2. 153. MIT, supra note 9, at 44. 154. Id. 155. IPCC, supra note 8, at 33. Note that Benson gives much higher estimates for the

cost of CO2, ranging from three dollars to ten dollars. Benson, supra note 123, at 13.



whether from the EOR or natural gas industry, such costs are fairly well-established and thus have a high degree of confidence.156 The actual cost of storage of the CO2 in a site should therefore be relatively minimal and predict-able.

The same cannot be said, however, for the construction of the storage sites. Substantial uncertainties exist about the makeup of CCS storage sites. To be-gin, major legal issues exist as to the ownership of the CO2. Put simply, the CCS industry would be unlike any in U.S. history. Though analogies can be drawn to the natural gas industry, the injection of wastewater, or EOR, there has never been an attempt to inject such huge quantities of substances under-ground for an extended period of time. This unique aspect of CCS has thus cre-ated substantial legal uncertainties about the ownership of CO2.157 Next, major regulatory hurdles exist, especially in the United States. Certain agencies have already approved pilot underground CO2 storage programs.158 However, other agencies have yet to take any action, despite the necessity of a regulatory re-gime to the success of the CCS industry. For example, the U.S. Geological Survey has yet to be given any instruction or resources to do any kind of stor-age capacity assessments, information that is crucial for the CCS industry.159 More generally, today there is simply no regulatory framework to govern CO2 storage over a long period of time at the quantities of emissions the U.S. pro-duces.160 These legal and regulatory uncertainties will undoubtedly hamper the development of any kind of CCS industry.

Finally, one CCS market actor not mentioned in much of the literature is the third-party intermediary. Though a CCS industry has yet to develop in any country, the E.U. currently has an ongoing CO2 market: the E.U. Emissions Trading Scheme (ETS).161 And, while a full analysis of the ETS is outside the scope of this Note, notably the ETS market has become “dominated” by third-party intermediaries such as emissions brokers and exchange platforms that co-ordinate the exchange of CO2.162 Although little discussion has occurred as to whether such third parties would develop in the CCS industry, such develop-ment is likely, especially given that it may be economical to outsource the co-ordination of the disposal of an emitter’s CO2 to such a third party. The analogy to natural gas marketers is fairly obvious: with the restructuring of the natural gas industry via Order 636 to allow market forces to act, such marketers be-

156. IPCC, supra note 8, at 33. 157. Id. 158. See, e.g., ENVTL. PROT. AGENCY, supra note 14, at 1 (providing information for

states permitting pilot projects for underground CO2 injection and storage). 159. MIT, supra note 9, at 46. 160. Id. at 56. 161. KARAN CAPOOR ET AL., STATE AND TRENDS OF THE CARBON MARKET 2006, at i

(2006). 162. Id. at 7.



came indispensable to the industry.163 Thus it is likely that third party interme-diaries will also play a part in a maturing CCS industry, though their actual role has yet to be determined.

The overall costs of capturing, compressing, transporting, and storing CO2 have been estimated to range from $30 to $70 per ton of CO2.164 Because no regulatory regime has been developed in the United States for reducing CO2, it is difficult to predict exactly how the CO2 will be given economic value. How-ever, one likely method would be to emulate the U.S. SO2 regime, in which SO2 emission permits are given to SO2 emitters such as power plants; the emit-ters must surrender a permit for each ton of SO2 emitted, with the permits being tradable on the market.165 Applied to the CCS industry, CO2 emitters would be forced to surrender a similar permit for each ton of CO2 emitted; therefore in order for the CO2 industry to be profitable the price for each permit must be above the total cost of capturing, compressing, transporting, and storing the CO2, otherwise the emitters will simply pay for permits while still emitting CO2.166 With CO2 properly priced, emitters will likely pay to store their CO2, either by building their own CCS systems or by paying compression, pipeline, and storage facilities to dispose of their CO2, in the hopes that the emitters can make a profit from selling the permits at a price above the cost of CCS per ton of CO2. However, because no regulatory regime currently exists, it is unclear exactly how the CO2 emissions will be valued or used. In conclusion, the mov-ing parts of the CCS industry thus currently exist; however, no CCS system per se currently exists, as it is characterized by substantial cost and regulatory un-certainties.

III. LESSONS FROM THE NATURAL GAS INDUSTRY

Focusing on the natural gas industry provides the benefit of envisioning what a fully mature CCS industry will look like; while today’s focus on getting the CCS industry to actually exist is undoubtedly critical, in the long-term what is more important is making sure the industry actually works, that is, is profit-able and provides incentives for emitters to engage in the CCS process and thus abate CO2 emissions. The natural gas industry provides three, interrelated les-sons on the future of the CCS industry, focusing on the most analogous por-tions of the two industries: storage, pipelines, and regulations.

The first lesson from the natural gas industry has to do with storing the gas and the ownership rights of the CO2. As noted above, in the natural gas industry

163. NaturalGas.org, Marketing, supra note 34. 164. Benson, supra note 123, at 13. 165. See, e.g., A. Denny Ellerman, Ex Post Evaluation of Tradable Permits: The U.S.

SO2 Cap-and-Trade Program, in OECD, EX POST EVALUATION OF TRADABLE PERMITS: METHODOLOGICAL AND POLICY ISSUES 1, 1-2 (2003).

166. Cf. CAPOOR ET AL., supra note 161, at 18 (noting that the recent EU CO2 allow-ances were too generous, resulting in a glut in the market).



such gas is never stored for longer than a season, due to the risk of it being lost in the storage facility. This is the antithesis of the CCS industry, in which the CO2 will be stored for a very long period of time, and ostensibly never re-moved. Because of this long-term storage, the question arises of who will own the stored CO2. This is a crucial question that will affect how the CCS industry develops, especially with respect to potential liability costs.

One option would be to follow the majority of the natural gas industry in having the emitters or shippers of the CO2 own the emissions themselves, with the storage facility merely holding the CO2 in perpetuity. However, this is likely not the best option for several reasons. First, if there were any storage leakage, the owners of the leaked CO2 could be held responsible, bringing up messy questions of liability (whose CO2 leaked? by how much?). Though the storage operators themselves would likely be liable,167 even the potential for such unlimited liability may kill the infant CO2 industry in its figurative crib. More specifically, having CO2 emitters keep ownership of the CO2 would im-pose substantial costs on the emitters, who would have to keep track of the lo-cation of all their CO2. While this may not be a major issue in the early stages of the industry, where one emitter’s CO2 goes to one storage site, as the indus-try matures and the infrastructure to transport CO2 over large distances comes on line, this may no longer be a viable or economical option.

Indeed, this is one of the crucial lessons of the natural gas industry: though locking in CO2 emitters into a fixed market structure may produce short-term benefits, in the long-term it is likely to stifle industry growth and efficiency. This is exactly what happened with the pipeline companies. Though it origi-nally made sense to have them locked in with specific producers via long-term contracts, as the industry matured, such rigid structure eventually became cum-bersome and nearly drove the pipelines to bankruptcy. Thus, a better option would be to require the storage operators to take ownership of the CO2. This ownership structure makes sense from both a scientific and economic back-ground. Scientifically, since the CO2 will eventually be reabsorbed into the sto-rage facility itself, it makes no sense for the emitters to own a substance that will eventually disappear. Economically, giving the storage facilities ownership of the CO2 gives those facilities the flexibility to shift CO2 for the most effi-cient outcome. In a mature CCS industry, it will not matter whose CO2 goes where, only that the storage rights in general have been secured. Thus, the first lesson from the natural gas industry is to not follow the natural gas industry: ownership rights should be given to the storage facility owners, rather than re-tained by the CO2 emitters.

The second lesson from the natural gas industry demonstrates that in a rela-tively mature industry, pipelines have massive amounts of market power, being both monopolists and monopsonists. Similar to the storage issue, this may not

167. This is the case for operators of EOR, as well as for underground wastewater in-jection. See Wilson & de Figueiredo, supra note 14, at 10,119-20.



be a concern that is readily apparent as the CCS industry begins; this is espe-cially so since co-location of the first CCS power plants may mean that actual transportation of the CO2 is negligible. Nonetheless, the natural gas industry experience teaches the value of thinking in the long-term. Once the CCS indus-try begins to mature, and as such convenient locations become rarer, it will likely begin to be more efficient to simply transport the CO2 rather than site the entire factory or power plant next to a storage facility. And, as Figure 1 above shows, major portions of the country are simply not located near natural gas storage facilities; this is especially true for the Northeast, where most of the land is not suitable for any kind of underground storage.168 Thus, it is ex-tremely likely that as the CCS industry matures, more and more CO2 will have to be transported, most likely via pipeline.

If and when such pipelines come on line, the natural gas industry experi-ence shows that they will have tremendous power. Because of the cost of build-ing pipelines, it is extremely likely that emitters will only be able to ship CO2 via one pipeline from their site. Pipelines will thus likely be monopsonists of an individual emitter’s CO2, though in this case CCS pipelines would face a ceil-ing of the cost of the CO2 (i.e., pipelines could only charge emitters up to the cost of the carbon, otherwise it would just be cheaper for the emitters to emit the CO2 without storage and pay the “tax” on the emissions). Similarly, if only one pipeline is connected to one storage facility, the pipelines will also likely be the only “seller” of CO2 to storage sites. This is especially the case if pipe-lines are allowed to develop as the natural gas industry did, with pipelines ver-tically integrating the entire industry, and able to refuse to ship any given com-pany’s gas. As the natural gas case study showed, such vertical integration eventually was so cumbersome that, once exacerbated by international shocks, it nearly brought the natural gas industry to its knees. Thus, in a mature indus-try the CO2 pipelines will need to be strictly regulated, and the best option is to insure that, like the present natural gas industry structure, pipelines are forced to be common carriers of CO2. As the case study showed, such open access quickly brings with it large efficiency gains, which are paramount for the CCS industry.

However, it may not be possible or even economical to regulate the pipe-lines in such a way immediately. If a mature pipeline industry is going to exist, a massive pipeline infrastructure is going to have to be installed in the United States. Given that the current CO2 pipeline mileage is two to three orders of magnitude below the current natural gas pipeline mileage, a lot of pipe is going to have to be laid. And though the theory of a “natural monopoly” has its crit-ics,169 it may make more sense to allow pipelines to act as monopolists for some set period of time, in order to incentivize the companies to lay the neces-sary infrastructure. Notably, the natural gas industry only restructured the role

168. FERC, supra note 43, at 3. 169. See, e.g., discussion supra Part I.B.



of pipelines after the pipelines themselves were already built. Before Order 636 pipeline companies were allowed to reap the monopoly rents from laying the pipelines. In fact, under the NGA, the FPC required the pipelines to enter into long-term contracts in order to receive approval to build new pipeline. Thus, in the early stages of the CCS industry, it may not make sense to force the pipe-lines to act as common carriers. This may rob them of the incentives to build the necessary CO2 pipeline infrastructure. An ideal solution may blend the two options, being somewhat equivalent to a patent. Pipelines will have a set period of time during which they can act as monopolists and monopsonists, and after which they must act as common carriers. Whichever option is chosen, the natu-ral gas industry tells a strong cautionary tale as to the powers of the pipelines: as the CCS industry matures, such market power will have to be closely ob-served and regulated.

Government regulation is, of course, the final lesson taught by the natural gas industry. Currently, the U.S. CCS industry faces an almost completely blank slate when it comes to federal regulation.170 Getting the regulation right will be one of the most difficult parts of the CCS solution, as it will set the in-dustry’s development path for the medium- to long-term. The natural gas indus-try experience shows how federal regulation can be both a benefit and a bur-den: though the early regulation of natural gas transportation was effective for such a structured industry, as the industry grew and the government mandate of regulating expanded, such regulation quickly became cumbersome. Indeed, the current natural gas industry may provide the most direct and beneficial analog to potential CCS regulation. Some form of government agency, equivalent in its functions to the FERC, may be the best solution as to how to regulate the industry. The commission would be independent, technocratic, and able to adapt as the CCS industry evolves. Indeed, the FERC shows exactly what an agency should do: as the industry evolved and matured, it was able to effec-tively restructure the natural gas industry in order to reflect more accurately the industry’s evolution and take advantage of market efficiencies. Moreover, such an agency would require little new congressional legislation, removing the need for political meddling. As the natural gas experience showed, this is exactly what happened with the FERC: Order 636 was issued at the FERC’s own be-hest, some 14 years after the NGPA, the last major piece of congressional natu-ral gas legislation.

At the same time, the natural gas industry also demonstrates the benefits of keeping the government out of regulating the price of the CO2 permits. This may not be entirely possible with respect to the CCS industry. If the industry does follow a “cap and trade” policy like the U.S. SO2 scheme171 or the EU

170. The EPA has only recently implemented regulations for pilot CO2 storage pro-jects. EPA, supra note 14 (outlining initial research and development phases for under-ground CO2 storage).

171. 40 C.F.R. §§ 72.1 et seq. (2007).



ETS, the government will inherently affect the price of the permits by setting the maximum cap on the supply of the permits. Nonetheless, the natural gas in-dustry shows the danger of trying to regulate directly the price of the permits themselves. Such regulation, especially when assigning different prices to dif-ferent types of the same commodity, invariably leads to market inefficiencies that often have disastrous effects, such as the Midwest school closings in the mid-1970s. The federal experiment with regulating the price of natural gas it-self ended with the government stepping almost completely aside with the pas-sage of the NGWDA. The lessons should be taken to heart for the CCS indus-try. While regulating the price of transporting or storing the CO2 may be feasible, regulating the cost of the CO2 itself, or rather the permits to emit CO2, will likely have negative consequences.

Taken together, the natural gas industry teaches three, interrelated lessons about the future of the CO2 industry: force storage facility owners to take own-ership of the CO2, maintain vigilant scrutiny over the role of the pipelines, and enact prudent legislation that will be able to regulate the evolving CCS industry flexibly.

CONCLUSION

The mature natural gas industry provides a number of excellent lessons for the infant CCS industry. Though many authors have analyzed portions of the incipient industry, very few have taken a long-term look at the CCS industry to answer the harder questions about how it will function on a daily level, such that it will remain profitable and efficient. The natural gas industry, after hav-ing undergone more than a century of growth, regulation, and restructuring, provides some important answers to these questions. Still, the natural gas anal-ogy is just that, an analogy, and thus imperfect in describing how the CCS in-dustry will look. Indeed, one of the prime lessons the natural gas industry teaches is to ignore its own methods when it comes to storage. Because of the fundamentally different roles the natural gas and CCS industries will play, it makes no sense to have the CO2 emitters retain ownership of their CO2. Simi-larly, the natural gas industry demonstrates the incredible market power of the pipelines and the ease with which such an industry can become vertically inte-grated. Though such integration may be beneficial as the CCS industry begins, over the long-term the natural gas industry shows that such rigid structure will be unsustainable, and thus must be carefully monitored. Finally, the natural gas industry presents one example of how to regulate the CCS industry, a challenge that will likely be the most important one the CCS industry faces as it struggles to become tenable. Federal agency regulation may provide the flexibility re-quired for an industry that is sure to evolve; however, such regulation should strive, as much as possible, to stay out of the CO2 market itself. With a success-ful CCS industry underway in the United States, we may be able to meet the coming challenges presented by greenhouse gases and climate change.

he atural as ndustry essons for the future...

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