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March 18, 2013 By wpengine

Deterring Disruption in the Derivatives Markets

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Matthew F. Kluchenek and Jacob L. Kahn*

Almost three years ago, in July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) amended section 4c(a) of the Commodity Exchange Act (CEA), to add three types of prohibited transactions deemed to be “disruptive of fair and equitable trading”—trading that violates bids and offers, trading with reckless disregard for orderly executions during the closing period, and so-called “spoofing.”[1] The enforcement division of the Commodity Futures Trading Commission (CFTC) trumpeted its new authority, claiming that the Dodd-Frank Act had given the agency a “bigger arsenal of weapons.”[2] Nonetheless, in the more than eighteen months since amended section 4c(a) became effective,[3] the CFTC has yet to file or settle a single enforcement case alleging violations of amended section 4c(a).

Market participants in the ever-growing commodities and swaps markets should not take comfort in this delay. As demonstrated by the cases discussed in this Article, the lack of CFTC enforcement of amended section 4c(a) appears to be a function of timing rather than a reflection of regulatory disinterest. Indeed, the CFTC has brought charges in the past based on all three types of trading activity that the CEA now expressly prohibits. These prosecutions are likely to continue, and the CFTC will probably pursue them with more frequency as a result of the amendments under Dodd-Frank.

The amendments to section 4c(a) generate two principal questions: first, what types of trading activity will the CFTC likely target as violations of the amended statute? Second, what must the CFTC prove to establish those violations? This Article attempts to answer these questions by explaining the key language in the amendment, including how the CFTC plans to interpret it, and by examining recent enforcement activity in the commodities industry to identify trends in the cases, including defenses the CFTC is likely to reject.

I. THE CFTC’S NEW AUTHORITY UNDER SECTION 4c(a) OF THE CEA

As amended by Dodd-Frank, section 4c(a) of the CEA (entitled “Prohibited Transactions”) includes the following section:

(5)  Disruptive practices.—It shall be unlawful for any person to engage in any trading, practice, or conduct on or subject to the rules of a registered entity that—

(A)   violates bids or offers;

(B)    demonstrates intentional or reckless disregard for the orderly execution of transactions during the closing period; or

(C)    is, is of the character of, or is commonly known to the trade as, “spoofing” (bidding or offering with the intent to cancel the bid or offer before execution).[4]

The CFTC was not required to promulgate rules to make these provisions effective, and it has not done so. Instead, it sought public comments on a list of questions related to the scope and nature of the prohibitions,[5] and then issued a proposed interpretive order (Proposed Interpretive Order) to explain how it intends to enforce amended section 4c(a).[6] A final interpretive order has not been released, but the Proposed Interpretive Order is effective until superseded by a subsequent order.

As explained below, although two of the three sub-parts under amended section 4c(a) appear to refer to specific trade practices, the boundaries for all three prohibitions remain largely undefined.

A. A Trader Who “Violates Bids or Offers” Faces Strict Liability under Section 4c(a)(5)(A)

Unlike the latter two prohibitions in amended section 4c(a)(5), each of which specifies a level of intent necessary to establish a violation, the prohibition of trading that “violates bids or offers” appears to create a strict liability offense because it does not indicate whether a trader must act with any degree of culpability.[7] The CFTC has adopted this same reading of the statute, and plans to bring enforcement actions for violations of section 4c(a)(5)(A) regardless of the trader’s intent.[8] In other words, traders who violate bids or offers may face regulatory enforcement regardless of whether they do so intentionally or negligently (or even through no fault of their own). The CFTC’s stance reflects its opinion (and its interpretation of Congress’s apparent opinion) that there is no legitimate reason for a trader to violate bids or offers.

But what exactly does it mean to “violate[] bids or offers”? Although the statute does not provide a definition, the CFTC plans to interpret this phrase as prohibiting a person from “buying a contract at a price that is higher than the lowest available offer price and/or selling a contract at a price that is lower than the highest available bid price.”[9] The CFTC, however, does not view section 4c(a)(5)(A) as creating a “best execution standard across multiple trading platforms and markets,” some of which may have different bid-ask spreads for the same contracts.[10] Thus, for example, even if the lowest offer for a near-month WTI Crude Oil futures contract on the Chicago Mercantile Exchange (CME) is below the lowest offer for the same contract on the IntercontinentalExchange (ICE), buying the contract on ICE would not constitute a violation of the prevailing offer on CME.

Two other key limitations help clarify this offense. First, the CFTC does not intend to apply the prohibition on violating bids and offers to traders’ attempts to “buy the board.”[11] That is, a trader legitimately may enter an order to purchase or sell such a large quantity of contracts, and at prices either higher or lower than the best existing bid or offer, that the trader’s order executes against all resting quotes, provided that the trader does so in accordance with the exchange’s rules.[12] Second, the CFTC’s Proposed Interpretative Order suggests that the prohibition on violating bids and offers applies only when a trader has control over the bids or offers she selects.[13] Thus, trades made on an electronic trading platform that uses automated order-matching software should not give rise to liability under this section to the extent that such software precludes parties from buying higher or selling lower than prevailing market prices.

Based on these final two limitations, it would appear that the majority of traders operating on electronic exchanges need not be overly concerned about inadvertently violating section 4c(a)(5)(A). The same cannot be said in the over-the-counter (OTC) markets, where traders may seek to negotiate privately with a counterparty for various reasons, including the size of the trader’s position or a past business relationship. If a negotiated transaction in these markets occurs outside the range of current bids or offers, one of the two parties may be in violation of section 4c(a)(5)(A). Despite acknowledging the public’s concern about how this provision will be applied in OTC markets,[14] the CFTC has declined to offer guidance on this point. Thus, the risk of strict liability remains for traders in OTC markets.

B. The Prohibition of Conduct that Disregards “Orderly Execution” under Section 4c(a)(5)(B) is Akin to a Stripped-Down Ban on Manipulation

The second “disruptive practice” added by the Dodd-Frank Act—trading that demonstrates “intentional or reckless disregard for the orderly execution of transactions during the closing period”—creates the most risk for market participants of the three new prohibitions for several reasons. First, it focuses specifically on trading activity during the closing period, which is one of the most actively traded periods during the trading day.[15] The concentration of trades at the end of the trading day leads to greater movements in price, which in turn attracts the attention of regulators. Now that the CEA expressly targets trading misconduct during the settlement period, the CFTC may be more willing to issue section 4g requests for information in the wake of large price movements.[16]

Second, and more importantly, the amendment to section 4c(a) does not define the phrase “orderly execution of transactions” or identify examples of activities that “disregard” such executions.[17] The CFTC likewise does not offer any definitions or examples in its Proposed Interpretive Order.[18] It merely identifies the “parameters” that exist in an orderly market, including “a rational relationship between consecutive prices, a strong correlation between price changes and the volume of trades, levels of volatility that do not materially reduce liquidity, accurate relationships between the price of a derivative and the underlying” and “reasonable spreads between contracts for near months and for remote months.”[19] Yet none of these “parameters” appears logically to relate to a specific type of conduct. They are closer in kind to the factors courts consider in manipulation cases in deciding whether “artificial prices” existed in the market.[20] Unlike in manipulation cases, however, a trader need not specifically intend to cause artificial prices[21] to violate section 4c(a)(5)(B). It is enough if the trader recklessly disregards the risk that her trades could cause disorderly executions—that is, the defendant is so careless as to the risk of causing disorderly executions that it is difficult to believe she “was not aware of what [s]he was doing.”[22] As a result, this section presents a more appealing enforcement option for the CFTC in manipulation cases that lack an obvious price effect or contemporaneous evidence of manipulative intent.

Finally, the CFTC’s Proposed Interpretive Order expands significantly the scope of trading that could violate section 4c(a)(5)(B) by suggesting that offending transactions could include (1) the mere submissions of bids and offers,[23] (2) trades done outside of the closing period,[24] and (3) cash market transactions in physical commodity markets where the contracts in question are used to establish a settlement price for a futures contract or swap.[25]

C. The Prohibition of “Spoofing” under Section 4c(a)(5)(C) Targets Order-Entry Misconduct, but May Cover Legitimate High-Frequency Trading Activity

The final disruptive practice added by the Dodd-Frank Act—so-called “spoofing”—is the only one defined in the CEA. According to section 4c(a)(5)(C), spoofing occurs when a trader enters a bid or offer “with the intent to cancel the bid or offer before execution.”[26] In other words, to establish a violation of this provision, the CFTC apparently must prove that a trader did not intend for her order to be filled. Whether the order is eventually filled is irrelevant; it is the trader’s intent at the time the order is submitted that determines the violation.[27]

But how can the CFTC prove the necessary intent given that every order, once submitted, is at risk of being executed? In certain cases, the CFTC may be able to rely on contemporaneous evidence of the trader’s intent, such as emails, instant messages, or phone recordings in which the trader confirms that she plans to submit and cancel her orders before execution. If no such evidence exists, the CFTC likely will rely on circumstantial evidence of the trader’s intent. Such evidence could include the number and pattern of orders submitted, the length of time orders remained active before being cancelled, the nature of the trading methodology, or the viability of the order in the first place (that is, whether the price of the order was close to the market price at the time of submission). Moreover, as discussed below, in cases involving automated trading, the CFTC is likely to demand that algorithmic code be provided for purposes of ascertaining intent. In essence, the CFTC will need to show that the most logical inference to be drawn from the trader’s activity is that she entered orders with the intent to cancel them before execution.

The intent calculus is clearly more difficult in the case of high-frequency traders. According to the CFTC’s draft definition from October 2012, high-frequency trading is a form of automated trading that uses computer algorithms to produce a high rate of orders, quotes or cancellations.[28] Mary Schapiro, the former chairman of the U.S. Securities and Exchange Commission, has estimated that high-frequency traders cancel “at least 90 percent of their orders.”[29] As such, these traders undoubtedly know at the time they submit their orders that they will cancel many, if not most, of them before execution. Knowledge of a high likelihood of cancellation is not the same as intent to cancel, but it could come close. Consider, for example, a high-frequency trading algorithm (controlled by an individual trader) that submits a large group of orders at one time at varying price points, some of which have no reasonable chance of being executed based on market prices at the time of entry. Why has the trader (or the algorithm) included orders unlikely to be filled? Did they enter the orders to provide cover for other, illegitimate trading activity? In a slightly different scenario, what if the trader programs the algorithm to immediately cancel all outstanding orders after a certain number of executions have occurred? In that case, is the trader not entering orders with intent to cancel most of them before execution? To answer some of these questions, the CFTC may need to review the computer code behind the trading algorithm, which, from the CFTC’s perspective, could provide more circumstantial evidence of intent. For these reasons and others, high-frequency traders could become a frequent target for the CFTC in enforcing the prohibition on spoofing in section 4c(a)(5)(C).

In addition, though this section specifically bans “spoofing,” it also prohibits a more general category of conduct that is “of the character” of spoofing.[30] In an apparent attempt to give meaning to this phrase, the CFTC in its Proposed Interpretive Order provided examples of conduct that does not necessarily fit the “intent to cancel” definition of spoofing but will still violate section 4c(a)(5)(C), including:

(i) Submitting or cancelling bids or offers to overload the quotation system of a registered entity, (ii) submitting or cancelling bids or offers to delay another person’s execution of trades; and (iii) submitting or cancelling multiple bids or offers to create an appearance of false market depth.[31]

Again, however, these are only examples. By prohibiting conduct “of the character” of spoofing, the Dodd-Frank Act left it to the CFTC to determine what other types of order-entry misconduct to prosecute under section 4c(a)(5)(C).

II. DRAWING GUIDANCE FROM PRIOR ENFORCEMENT ACTIONS INVOLVING CONDUCT NOW PROHIBITED BY SECTION 4c(a)

Although the Dodd-Frank Act added three new prohibited practices to CEA section 4c(a), the practices themselves are not new, nor is the CFTC’s stance on their legality. As discussed below, both the CFTC and self-regulatory agencies have brought charges in the past based on the same conduct now expressly prohibited under Dodd-Frank. These cases provide additional insight into the type of conduct the CFTC may prosecute in the future under CEA section 4c(a)(5).

A. The CFTC Believes the Violation of Bids and Offers is a Serious Enough Offense to be Charged as Market Manipulation

The CFTC has filed just one enforcement action based on a trader’s violation of bids and offers—In the Matter of Anthony J. DiPlacido[32]—but that case is also the only market manipulation case the agency has ever successfully litigated to final judgment. In DiPlacido, the CFTC accused the respondent, a registered floor broker on the New York Mercantile Exchange (NYMEX) trading on behalf of his client, Avista, Inc., of attempting to manipulate and successfully manipulating the price of certain electricity futures contracts traded on NYMEX in violation of sections 6(c), 6(d) and 9(a)(2) of the CEA.[33] In particular, the CFTC alleged that DiPlacido traded in large quantities during the closing period and either offered at prices below the prevailing bid price in the pit (i.e., violated bids), or bid at prices higher than the prevailing offer prices (i.e., violated offers).[34]

The Administrative Law Judge found DiPlacido liable for attempted and actual manipulation,[35] and the CFTC affirmed. The U.S. Court of Appeals for the Second Circuit later affirmed the CFTC’s decision by summary order.[36] Among other things, the CFTC concluded that DiPlacido’s repeated violation of bids and offers was sufficient to establish (1) that he acted with manipulative intent because his conduct had “no apparent economic rationale,”[37] and (2) that his conduct produced artificial prices because he necessarily “paid more than he had to” for the contracts and thus injected artificial forces in the market.[38] The CFTC relied on a 1971 decision by its predecessor agency as support for both of these conclusions even though the respondent in that case was not found to have violated any bid or offer.[39]

The CFTC’s decision in DiPlacido supports its stated intent in the Proposed Interpretive Order to treat the offense of violating bids and offers in section 4c(a)(5)(A) as a strict liability offense. Indeed, the CFTC can point to an adjudicated decision by the full Commission—affirmed by the Second Circuit, no less—holding that there is no legitimate reason for a trader to violate bids or offers.[40] DiPlacido tried to challenge this presumption in his case, arguing that his conduct did have a legitimate purpose: he was trading aggressively in order to help his client quickly unwind its hedge of positions in other markets.[41] But the CFTC and the Second Circuit rejected this argument without any discussion, and likely will do so again in the future if it is raised in defense of charges that a trader violated bids or offers under section 4c(a)(5)(A). In other words, although a single transaction may be part of a much larger, complicated trading strategy, that does not excuse the trader from liability for violations arising out of the transaction.

B. The CFTC Faces a Much Easier Route to Prosecuting Disorderly Trading during the Closing Period

The most reasonable interpretation of the new prohibition of trading that disregards orderly executions during the closing period is that Congress was trying to make it easier for the CFTC to prevent conduct more commonly known as “marking” or “banging” the close. According to the CFTC, “banging the close” is

[a] manipulative or disruptive trading practice whereby a trader buys or sells a large number of futures contracts during the closing period of a futures contract (that is, the period during which the futures settlement price is determined) in order to benefit an even larger position in an option, swap, or other derivative that is cash settled based on the futures settlement price on that day.[42]

The CFTC previously charged this type of activity as manipulation.[43] For example, in its case against the now-defunct Amaranth Advisors LLC, the CFTC alleged that the hedge fund, its affiliates, and a key employee sold an excessive number of natural gas futures contracts during the closing period with the intent of lowering the futures settlement price because they knew that a lower settlement price would benefit the defendants’ even larger short position in natural gas swaps.[44] The CFTC charged the defendants with attempted manipulation, and eventually settled those charges for $7.5 million after the court denied the defendants’ motion to dismiss.[45]

The Amaranth settlement, though a positive result for the CFTC, did not improve the agency’s record in adjudicated manipulation cases, [46] where the CFTC has prevailed just once in its nearly 40-year history.[47] As explained by CFTC Commissioner Bart Chilton in 2009, prior to the enactment of the Dodd-Frank Act:

Proving manipulation under current law is so onerous as to be almost impossible. Under current law, the CFTC is required to prove “specific intent” to create an artificial price—a price not responsive to the forces of supply and demand. . . . Specific intent to manipulate is not always equivalent to intent to deceive—it requires something more, and it’s also very difficult to prove the existence of an “artificial price.” All in all, it makes for a very difficult legal burden, not to mention that it leaves a lot of wiggle room for mischief that is clearly prohibited by the Act.[48]

In contrast to the specific intent standard described by Commissioner Chilton and required in “banging the close”-type cases brought prior to the Dodd-Frank Act,[49] the CFTC can now prosecute disorderly trading during the closing period under section 4c(a)(5)(B) and establish a violation by showing that the defendant acted recklessly.[50] The difference between these two standards of intent cannot be overstated. Whereas recklessness requires proof that the defendant’s conduct was highly unreasonable, specific intent requires proof that the defendant’s subjective goal was to bring about the prohibited result. Thus, for example, while a defendant carrying out a legitimate trading strategy cannot, as a matter of law, act with the specific intent to cause disorderly executions during the closing period, the same strategy could be deemed reckless—thereby satisfying section 4c(a)(5)(B)—if the defendant ignored the likely effect of her conduct.[51] For this reason, the CFTC is likely to file far more cases based on misconduct during the closing period than it has in the past.

It should also be noted that the CFTC has not restricted its authority under section 4c(a)(5)(B) to “banging the close” cases. Though several market participants suggested in response to the CFTC’s notice of proposed rulemaking that the prohibition under section 4c(a)(5)(B) be limited to manipulative conduct similar to “banging the close,”[52] the CFTC declined to adopt such a limitation. Thus, while prior “banging the close” cases are instructive, they do not cover the range of possible violations of section 4c(a)(5)(B).

C. The CFTC has Charged “Spoofing” under Two Other Sections of the CEA, but Neither Section Clearly Fits the Violation

Of the three new prohibited practices under amended section 4c(a)(5), the prohibition on “spoofing” is arguably the one with the clearest history of prior enforcement by the CFTC, as well as by exchanges. In the past two years, the CFTC has settled two enforcement actions based on conduct now defined in the CEA as spoofing,[53] and the CME and Chicago Board of Trade (a designated contract market within CME Group) have settled three such actions.[54] In all but one of these matters,[55] the conduct in question occurred prior to the enactment of the Dodd-Frank Act—that is, prior to the time the CEA specifically prohibited spoofing.[56]

The alleged spoofing violations in all of these cases occurred during the pre-opening session on CME’s electronic trading platform, Globex. Orders cannot be executed during this pre-opening session. However, except for the last 30 seconds before the market opens, orders can be cancelled at any time. At pre-determined intervals, CME calculates what is known as an Indicative Opening Price (IOP) using data from the unexecuted orders sitting in Globex. Once the market opens, trading will begin at a price somewhere in-between the unexecuted bids and offers, and the IOP provides a running estimate of this figure. The IOP is sent to Globex users and recipients of CME’s data feed, and becomes available to the public shortly thereafter.[57]

The traders sanctioned by the CFTC and CME Group each sent (and later cancelled) large orders into Globex during the pre-opening session at varying prices. The orders moved the IOP up or down, depending on the prices in the orders. Although other market participants could see the movement in the IOP, they had no way of knowing how many orders were being entered into Globex and at what prices. The sanctioned traders, on the other hand, were able to discern the depth of support at different price levels because they knew the IOP had moved in response to their orders. If, for example, the sanctioned trader sent an order to purchase 100 contracts at $1.00 and saw that the IOP moved less for that order than it had for an order at $1.05, the trader would know that there was more market depth at $1.00. The traders then used this information to make trading decisions after the market opened.[58]

In the two CFTC enforcement actions, Bunge Capital Markets and Gelber Group, the CFTC charged the respondents with violating sections 4c(a)(2)(B) and 9(a)(2) of the CEA.[59] Section 4c(a)(2)(B) makes it unlawful to cause a non-bona fide price to be reported,[60] and section 9(a)(2) makes it unlawful to cause false, misleading or knowingly inaccurate reports to be delivered that affect the price of a commodity.[61] Neither of these sections, however, clearly fits the charge of spoofing. In particular, section 4c(a)(2)(B) requires a “transaction,”[62] and an unexecuted order does not clearly constitute a “transaction.” Similarly, section 9(a)(2) requires that the inaccurate reports “affect or tend to affect the price of any commodity in interstate commerce,”[63] and though the IOP does relate to the price of the underlying commodity to be traded, once the offending orders are cancelled, the IOP no longer reflects those orders. Thus, more so than with the other new disruptive practices added to the CEA, the new prohibition on “spoofing” provides a cleaner path for CFTC enforcement than existed prior to the Dodd-Frank Act.

In terms of conduct that the CFTC might charge as being “of the character of” spoofing, cases from the securities industry may offer some guidance. Spoofing in the securities industry is a bit different than in the commodities industry in that it is considered a form of market manipulation and requires that certain orders be executed.[64] In particular, a securities trader engages in spoofing when she “creates a false appearance of market activity by entering multiple non-bona fide orders on one side of the market, at generally increasing (or decreasing) prices, in order to move that stock’s price in a direction where the trader intends to induce others to buy (or sell) at a price altered by the non-bona fide orders.”[65] Often, the trader will cancel any orders that have not been filled after she sells (or buys) at artificially high (or low) prices.[66] This activity is different than the offense of spoofing now prohibited in the CEA because it does not necessarily require a trader to enter orders with the intent to cancel them before execution. Nevertheless, the activity appears sufficiently related to fall under the category of conduct “of the character of” spoofing. The activity thus may give rise to a violation of section 4c(a)(5)(C) if it occurs in the commodities industry.

CONCLUSION

Although it remains to be seen exactly how the CFTC will enforce the new prohibitions of disruptive trading practices found in section 4c(a)(5) of the CEA, the CFTC’s Proposed Interpretative Order and past record of enforcement activity together provide some answers. Congress clearly intended to make it easier for the CFTC to police disruptive trading activity in the derivatives industry, and appears to have accomplished this goal. It is only a matter of time until the CFTC puts its new authority to work.

 


Preferred citation: Matthew F. Kluchenek & Jacob L. Kahn, Deterring Disruption in the Derivatives Markets: A Review of the CFTC’s New Authority over Disruptive Trading Practices, 3 Harv. Bus. L. Rev. Online 120 (2013), https://journals.law.harvard.edu/hblr//?p=3159.

* Matthew Kluchenek is a Partner, and Jacob Kahn is an Associate, in the Securities and Futures Group at Schiff Hardin LLP.

[1] Dodd-Frank Wall Street Reform and Consumer Protection Act, Pub. L. No. 111-203, § 747, 124 Stat. 1376, 1739 (2010).

[2] Christopher Doering, New CFTC Enforcement Chief Vows to be Aggressive, Reuters, May 5, 2011, available at http://www.reuters.com/article/2011/05/05/financial-regulation-cftc-enforcement-idUSN059778220110505.c

[3] These provisions took effect on July 16, 2011. See Antidisruptive Practices Authority Contained in the Dodd-Frank Wall Street Reform and Consumer Protection Act, 75 Fed. Reg. 67,301, 67,302 (proposed Nov. 2, 2010) (requesting comments as part of advance notice of proposed rulemaking and explaining that the provisions amending section 4c(a) will take effect 360 days after the enactment of the Dodd Frank Act, which took place on July 21, 2010).

[4] 7 U.S.C. § 6c(a)(5) (2012).

[5] See Antidisruptive Practices Authority Contained in the Dodd-Frank Wall Street Reform and Consumer Protection Act, supra note 3, at 67,301.

[6] Antidisruptive Practices Authority, 76 Fed. Reg. 14,943 (proposed Mar. 18, 2011) [hereinafter Proposed Interpretive Order].

[7] 7 U.S.C. § 6c(a)(5).

[8] Proposed Interpretive Order, supra note 6, at 14,946.

[9] Id. at 14,945­­–­­46.

[10] Id. at 14,946.

[11] Id.

[12] Id.

[13] Id. The concept of “control” may prove elusive. For example, does control exist if a developer programs an algorithm that is not susceptible to change or modulation by a trader?

[14] See id. at 14,945 nn.29 & 33 (citing comment letters).

[15] David Cushing & Ananth Madhavan, Stock Returns and Trading at the Close, 3 J. Fin. Markets 45, 46, 66 (2000) (measuring impact of increased end-of-day trading on stock prices), available at http://www.sciencedirect.com/science/article/pii/S1386418199000129.

[16] See generally 7 U.S.C. § 6g (2012) (describing the trading records that must be maintained and available for inspection).

[17] Id. § 6c(a)(5)(B).

[18] See Proposed Interpretive Order, supra note 6.

[19] Id. at 14,946.

[20] See, e.g., Sanner v. Bd. of Trade of Chi., No. 89 C 8467, 2001 WL 1155277, at *4 (N.D. Ill. Sept. 28, 2001).

[21] See Prohibition on the Employment, or Attempted Employment, of Manipulative and Deceptive Devices and Prohibition on Price Manipulation, 76 Fed. Reg. 41,398, 41,407 (July 14, 2011) (to be codified at 17 C.F.R. pt. 180) (articulating the traditional four-part test for commodities manipulation).

[22] See Proposed Interpretive Order, supra note 6, at 14,946, n.40 (citing Drexel Burnham Lambert, Inc. v. Commodity Futures Trading Comm’n, 850 F.2d 742, 748 (D.C. Cir. 1988 (quoting First Commodity Corp. v. Commodity Futures Trading Comm’n, 676 F.2d 1, 7 (1st Cir. 1982))).

[23] Id.

[24] Id.

[25] Id. at 14,946 n.42.

[26] 7 U.S.C. § 6c(5)(C) (2012).

[27] See Proposed Interpretive Order, supra note 6, at 14,947.

[28] Working Group 1, Subcomm. on Automated and High Frequency Trading, CFTC Technology Advisory Comm. 4 (Oct. 30, 2012), http://www.cftc.gov/ucm/groups/public/@newsroom/documents/file/tac103012_wg1.pdf (last visited Feb. 21, 2013).

[29] Jesse Westbrook, SEC Considers Rules for High-Frequency Traders After Plunge, Bloomberg (Sept. 7, 2010), http://www.bloomberg.com/news/2010-09-07/sec-weighs-new-rules-for-high-frequency-traders-after-may-6-market-plunge.html.

[30] 7 U.S.C. § 6c(5)(C).

[31] Proposed Interpretive Order, supra note 6, at 14,947 (emphasis added).

[32] Anthony J. DiPlacido, CFTC Docket No. 01-23, 2008 WL 4831204 (Nov. 5, 2008), aff’d sub nom. DiPlacido v. Commodity Futures Trading Comm’n, 364 Fed. Appx. 657 (2d Cir. 2009) (summary order). Though DiPlacido is the only CFTC case based clearly on a trader’s violation of bids or offers, it is possible that exchanges have brought disciplinary proceedings against members for violation of exchange rules prohibiting this same conduct. See Complaint at 11­–12, U.S. Commodity Futures Trading Comm’n v. Welsh, No. 12 CV 1873, 2012 WL 846664 (S.D.N.Y. Mar. 14, 2012) (alleging that defendant instructed NYMEX floor clerk to violate exchange rules “prohibiting buying at a price higher than the prevailing bid-ask spread” in his attempt to manipulate prices upward).

[33] DiPlacido, 2008 WL 4831204, at *1–2.

[34] See id. at *3–8.

[35] Id. at *1.

[36] DiPlacido, 364 Fed. Appx. at 659.

[37] DiPlacido, 2008 WL 4831204, at *28.

[38] See id. at *31 (quoting David G. Henner, 30 Agric. Dec. 1151, 1194 (U.S.D.A. 1971).

[39] See David G. Henner, 30 Agric. Dec. 1151 (U.S.D.A. 1971). The respondent in Henner “bought the board” in the closing seconds of the trading day and then immediately bid for an additional futures contract (later executed) at a price higher than any trades that day—but no offers were standing at that point, so none were “violated.” See id. at 1161–62 The Department of Agriculture held that the respondent’s conduct amounted to manipulation because he had “intentionally paid more than he would have had to pay . . . for the purpose of causing the closing quotation [to increase].” Id. at 1174.

[40] See DiPlacido, 2008 WL 4831204, at *26.

[41] See Reply Brief for Petitioner at 14, DiPlacido, 364 Fed. Appx. 657 (No. 08-5559-ag), 2009 WL 7768656, at *13.

[42] See CFTC Glossary, U.S. Commodity Futures Trading Comm’n, http://www.cftc.gov/consumerprotection/educationcenter/cftcglossary/glossary_b (last visited Mar. 11, 2013) (emphasis added).

[43] See, e.g., U.S. Commodity Futures Trading Comm’n v. Amaranth Advisors L.L.C., 554 F. Supp. 2d 523, 528 (S.D.N.Y. 2008); Christopher Louis Pia, CFTC No. 11-17, 2011 WL 3228315, at *1 (July 25, 2011); Complaint at 2, U.S. Commodity Futures Trading Comm’n v. Welsh, No. 12 CV 1873, 2012 WL 846664 (S.D.N.Y. Mar. 14, 2012).

[44] Amaranth Advisors, 554 F. Supp. 2d at 528.

[45] U.S. Commodity Futures Trading Comm’n v. Amaranth Advisors L.L.C., No. 07 Civ. 6682(DC), 2009 WL 3270829 (S.D.N.Y. Aug. 12, 2009).

[46] See, e.g., Soybean Futures Litig., 892 F. Supp. 1025, 1043 (N.D. Ill. 1995) (“The court recognizes that manipulation cases generally have not fared well with either the CFTC or the courts.”).

[47] See DiPlacido v. Commodity Futures Trading Comm’n, 364 Fed. Appx. 657 (2d Cir. 2009).

[48] Bart Chilton, Comm’r, Commodity Futures Trading Comm’n, “De Principatibus” (Oct. 21, 2009), http://www.cftc.gov/PressRoom/SpeechesTestimony/opachilton-28 (last visited Mar. 11, 2013); see also Jerry W. Markham, Manipulation of Commodity Futures Prices—The Unprosecutable Crime, 8 Yale J. on Reg. 281, 356–57 (1991) (“The small number of cases brought and the very small number of respondents who have been subject to significant sanctions, particularly in contested cases, suggest that manipulation is virtually an unprosecutable crime. This is due to the difficulty of meeting the standards of manipulation . . . . Even where a gross manipulation occurs, the government is still faced with the imposing burden of proving that the price was artificial and that the trader was attempting to create an artificial price rather than exploiting a market situation based upon natural forces.”).

[49] See, e.g., Amaranth Advisors, 554 F. Supp. 2d at 532–34.

[50] 7 U.S.C. § 6c(a)(5)(B) (2012).

[51] See Proposed Interpretive Order, supra note 6, at 14,946.

[52] Id. at 14,946 n.39 (citing a letter from the Futures Industry Association as one example).

[53] Gelber Group, LLC, CFTC Docket No. 13-15, 2013 WL 525839 (Feb. 8, 2013); Bunge Global Markets, Inc., CFTC Docket No. 11-10, 2011 WL 1099346 (Mar. 22, 2011).

[54] Michael Wisnefski, CME File No. 11-08127 (Aug. 6, 2012) (on file with authors); Gelber Group LLC, CME File No. 09-06442-BC (Nov. 17, 2011) (on file with authors); Kyle McBain, CBOT File No. 10-04622-BC (Nov. 14, 2011) (on file with authors).

[55] McBain, CBOT File No. 10-04622-BC.

[56] While the CEA did not expressly prohibit spoofing prior to the Dodd-Frank Act, the offense was clearly on the minds of regulators at the exchange level. In January 2010, for example, CME Group issued an advisory notice reminding market participants that “all orders entered on Globex during the pre-opening are expected to be entered in good faith for the purpose of executing bona fide transactions,” and threatening disciplinary action for all attempts to identify market depth or manipulate the IOP by entering and cancelling orders in the pre-opening session. Advisory Notice, CME Group, Improper Conduct With Respect to Pre-Opening Orders Entered on CME Globex, Advisory No. CME Group RA1001-5 (Jan. 11, 2010), http://www.cmegroup.com/tools-information/lookups/advisories/market-regulation/CMEGroup_RA1001-5.html; see also Advisory Notice, CME Group, Improper Conduct With Respect to Pre-Opening Orders Entered on CME Globex, Advisory No. CME Group RA1103-5 (Sept. 20, 2011), http://www.cmegroup.com/rulebook/files/CME_Group_RA1103-5.pdf.

[57] See Gelber Group, LLC, 2013 WL 525839, at *2; Bunge Global Markets, 2011 WL 1099346, at *1–2.

[58] See Gelber Group, LLC, 2013 WL 525839, at *2; Bunge Global Markets, 2011 WL 1099346, at *1–2.

[59] Gelber Group, LLC, 2013 WL 525839, at *3–4; Bunge Global Markets, 2011 WL 1099346, at *3–4.

[60] 7 U.S.C. § 6c(a)(2)(B) (2012).

[61] Id. § 13(a)(2).

[62] Id. § 6c(a)(2)(B).

[63] Id. § 13(a)(2).

[64] See, e.g., Biremis Corp., Exchange Act Release No. 34-68456, 2012 WL 6587520, at *2 (Dec. 18, 2012); Joseph R. Blackwell, Securities Act Release No. 33-8030, 2001 WL 1408738, at *2 (Nov. 5, 2001).

[65] Biremis Corp., 2012 WL 6587520, at *2.

[66] See id. at *7.

Filed Under: Derivatives Regulation, Featured, Home, U.S. Business Law, Volume 3

March 14, 2013 By wpengine

Toward an Economic Model for the Taxation of Derivatives and Other Financial Instruments

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David S. Miller*

I.      Introduction

Our federal income tax system, a hundred years old this year, was conceived in an age of nascent capital markets, characterized by illiquidity[1] and high volatility.[2] Time value concepts were little understood,[3] options could not be priced,[4] and the concept of economic income was still decades away.[5]

The tax system revolved around cash, and realization was the guiding principle—the concept that income is not earned, and therefore not taxed, until a taxpayer actually sells property for cash or exchanges it for materially different property.[6] The realization requirement was viewed as so fundamental to our income tax system that for some time it was imbued with constitutional significance.[7]

However, taxpayers soon realized that financial and commercial transactions revolve not around cash and realization, but around economic income, and this allowed them to exploit the artificial realization requirement, again and again. Each time, eventually, Congress or the Internal Revenue Service (IRS) reacted.

After a century, our federal system for taxing financial instruments is truly Ptolemaic.[8] Realization remains at its center, but Congress and the IRS have again and again attempted to adjust it to function in a world that truly revolves around economic income. The wash sale rules, the straddle rules, the capital loss limitation rules, the contingent payment debt instrument rules, the constructive ownership rules, the constructive sale rules, and the contingent swap rules are the epicycles of our tax system. And yet we retain our realization tax system as stubbornly as Europe retained Ptolemy’s geocentric system through the Middle Ages.

But perhaps this will change. On January 24, Congressman Dave Camp (R-MI), the Chairman of the House Ways and Means Committee, released the discussion draft of a bill that would tax derivatives under a mark-to-market system of taxation.[9] This truly Copernican proposal would replace our entire federal system of taxing derivatives with a radically different but infinitely simpler model that would finally correspond to economic reality. If it were enacted, it would represent the most significant change in the history of our federal tax system. But, by shattering the realization paradigm, the Camp proposal suggests the possibility of something even more revolutionary: a fundamental reformation of our entire concept of taxable income.

Part II of this Article briefly recounts the history of the federal taxation of financial instruments with a series of vignettes. Part III discusses the Camp proposal and the hope it offers for our federal income tax system.

II.    A Brief History of the Federal Income Taxation of Financial Instruments

A.   The Wash Sale Rules

The federal income tax was enacted on October 3, 1913 but didn’t take effect until 1916.[10] Within five years, wealthy taxpayers had already learned how to use the realization requirement to generate “paper” tax losses while deferring their real economic gains. At hearings before the Senate Finance Committee on October 1, 1921, T.S. Adams of the Treasury Department testified:

Men are now selling securities at 10 o’clock in the morning and buying them back at 12 o’clock. In order to claim a loss. The House believed that that should not be permitted. We have had considerable trouble with it, where the taxpayer does that and gets back identically the same securities at the present time.[11]

Senator Charles Curtis from Kansas interjected.

The men doing that are men with enormous incomes . . . One man told me—who was many times a millionaire—that he did that, and that that year he made over $1,000,000; and yet he deducted from his tax where he sold his stock at a loss, gave himself what he was allowed for the loss and turned around a short time later and bought the same stock back at about the same price he sold it for.[12]

Senator Curtis was describing the “timing option” inherent in the realization rule: taxpayers can accelerate their losses by selling at a loss but can defer their gains indefinitely by simply holding. The timing option is most blatant when the taxpayer sells a security at a loss, simultaneously repurchases the very same security, and then retains it as it appreciates.

That year, Congress enacted the wash sale rules, which prevent a taxpayer who sells stock or securities at a loss and also acquires substantially identical stocks or securities within a specified period of time from claiming that loss.[13] The wash sale rules do not modify the realization requirement; instead, they simply defer the taxpayer’s loss.[14]

The initial wash sale rules proved ineffectual and were amended substantially in 1988 and again in 2000 to address increasingly sophisticated derivative transactions.[15] Despite these changes, the wash sale rules present insufficient barriers to abuse. For instance, David Schizer has listed seven “perfect end runs” around them.[16]

B.   Straddles

Revenue Ruling 77-185 describes a transaction in which a taxpayer on August 1, 1975 simultaneously sold silver future contracts for July delivery and purchased an identical number of silver futures contracts for March delivery, effectively hedging her economic exposure.[17] Three days later, after the March contracts depreciated, the taxpayer sold them at a loss and purchased an identical number of May contracts.[18] The taxpayer reported a loss from the sale of the March silver contracts in 1975.[19] On February 18 of the following year, the taxpayer simultaneously sold the May contracts and purchased July contracts to cover the short position.[20] That year, the taxpayer reported a long-term capital gain.[21]

While a wash sale allowed a taxpayer to recognize a tax loss without changing her economic position, at least the taxpayer experienced an economic loss. The straddle transaction described in Revenue Ruling 77-185 had no appreciable effect on the taxpayer’s economic position (because the taxpayer remained completely hedged), the taxpayer had no reasonable expectation of deriving an economic profit, and the transaction was consummated only to generate a current short-term capital loss offset by a future long-term capital gain.[22] Although the transaction was a tax shelter,[23] the realization rule made it possible.

In 1981, Congress addressed these transactions with a narrow mark-to-market rule in section 1256 that applied a reduced “blended” rate of tax to certain futures contracts and short-term options.[24] Perversely, by reason of the blended rate, these marked-to-market futures contracts and options are more lightly taxed than they were under realization.[25] For all other instruments, Congress let realization lie, but attempted to shackle it with the straddle rules, which deny deductions, defer losses, and toll holding periods for positions in straddles.[26] As was the case with the wash sale rules, however, the collar was too loose and in 1984, Congress tightened it.[27]

The 1984 Act was not a decade old before taxpayers found a chink in the straddle armor. A new financial product, initially called DECS—for Dividend Enhanced Convertible Stock—allowed corporate taxpayers with appreciated securities to hedge and monetize their economic exposure and claim current deductions for the cost of the financing, seemingly in violation of the rule that denies deductions for positions in a straddle.[28] The IRS attempted to rein in DECS with regulations in 1995[29]and more proposed regulations in 2001,[30] but it finally took an act of Congress in 2004 to unambiguously deny interest deductions on DECS used to hedge appreciated positions.[31]

C.   Shorts-Against-the-Box: The Lauder Transaction and the “Constructive Sales” Rules of Section 1259

In 1995, Estée Lauder and her sons, Ronald and Leonard, invoked the realization requirement to avoid all tax on their highly appreciated Estée Lauder stock.[32] Estée loaned her stock to her sons; they loaned theirs to her; and they all sold the borrowed stock into the market.[33] This transaction was a “short-against-the-box.” Under realization’s great generosity, because none of the three had sold their own shares, all of their tax was deferred indefinitely, even though they were subject to none of their stock’s benefits or burdens, and they received cash. Congress responded in predictable fashion. Realization was retained, but the specific transaction was shut down with the “constructive sale” rules of section 1259.[34]

These examples are not the only ones. The loss limitation rules,[35] the original issue discount[36] and contingent payment debt instrument rules,[37] the conversion transaction rules of section 1258,[38] the constructive ownership rules of section 1260,[39] and the contingent swap rules[40] were all legislative or regulatory responses to realization rule abuse by taxpayers. Yet these rules still have not thwarted taxpayers and so today, taxpayers remain free to choose a tax treatment that minimizes their taxes. Three examples follow.

D.   The Continued Benefits of Realization

1.    The Taxation of Credit Default Swaps

Credit default swaps can be structured as options for tax purposes or they can be structured as “notional principal contracts.”[41] If they are structured as options, under the realization rule, the taxpayer can defer tax on the premiums.[42] If they are structured as notional principal contracts, the taxpayer can rely on the “contingent swap” regulations proposed by the IRS to claim immediate ordinary losses when the risk of default increases.[43] The proposed contingent swap regulations turn off realization and require a modified mark-to-market system of taxation for these contracts.[44] Some taxpayers initially took the position that credit default swaps were options and deferred the premiums, and then, after the market turned downward, changed their minds and treated the very same credit default swaps as notional principal contracts to claim immediate ordinary losses.[45]

2.    The Use of “Variable Prepaid Forward Contracts” To Monetize Appreciated Stock

Wealthy individuals with appreciated stock can enter into variable prepaid forwards that hedge their downside risk, and provide them with cash, all tax-free. [46] Although the IRS challenged one variant of this transaction, in Revenue Ruling 2003-7, it declared the basic technique completely legal. [47]

3.    Structured Notes and the “Open Transaction” Doctrine

Finally, in the past ten years, over $250 billion in structured notes have been issued in public transactions registered with the SEC.[48] Among these structured notes is a type that promises its holders a relatively secure principal amount at maturity plus contingent interest tied to the return of an equity index like the S&P 500. Notes like these resemble contingent payment debt instruments that would subject an investor to annual original income accruals and ordinary income at maturity.[49] But these notes are structured as prepaid forward contracts. Under the open transaction doctrine of our realization-based tax system, holders pay no tax until maturity and then, at maturity, are eligible for long-term capital gains rates.

These notes are not tax shelters in any nefarious sense. They are registered with the SEC in public documents, and their beneficial tax treatment is simply the natural consequence of our realization tax system.

The deferral permitted by credit default swaps, variable prepaid forwards, and structured notes is an artifact of our realization system. The ability of taxpayers to choose their tax treatment arises because there is no single guiding principle governing the taxation of financial instruments. Ultimately, our system is numbingly complex because Congress and the IRS must repeatedly correct it because it has no basis in reality.

III.  The Camp Proposal

Chairman Camp’s proposal would require any derivative held by a taxpayer at the end of a taxable year to be treated as sold for its fair market value on the last day of the taxable year.[50] Any mark-to-market gain or loss (and any gain or loss on an actual sale) would be treated as ordinary gain or loss; the taxpayer’s basis in the position would be adjusted for the gain or loss; and any loss could be carried forward to offset other ordinary income.[51] Moreover, if a taxpayer uses a derivative to hedge a non-derivative, the non-derivative would also be subject to mark-to-market treatment.[52] For example, if a taxpayer were to hedge his appreciated stock by buying a forward or a put option, not only would the forward or put be marked-to-market, but also the stock.

The Camp proposal is transformative. In an instant, our federal tax system for taxing derivatives would abandon the realization rule that characterized its first hundred years and begin its second century based on economic income. This paradigm shift would represent the most dramatic reform to our federal tax system since its introduction, and would do what a century of economists and tax lawyers have said would be impossible.

As the brief history in Part II illustrates, Camp’s proposal would replace half a dozen sets of rules with a single rule: mark-to-market. For the derivatives to which it applies, the proposal would obviate the wash sale rules,the straddle rules, the short sale rules, the capital loss limitations, the notional principal contract rules, the contingent swap rules, and the constructive ownership and sale rules. The law would be infinitely simpler and abuse all but impossible.

The key to the provision is its definition of derivative. Derivative includes any “evidence of an interest” in any share of stock, partnership interest, any evidence of indebtedness, any real estate (except for single parcels or inventory), any actively-traded commodity, and any currency.[53] It also includes any “notional principal contract” (i.e., a swap, as specially but broadly defined) and any “derivative financial instrument” with respect to a derivative.[54] Finally, if a debt instrument has an embedded derivative component, the debt instrument is bifurcated into two separate instruments: a derivative that is subject to mark-to-market treatment, and a debt instrument that is not.[55]

This definition of derivative is notable for its breadth. It would cover not only all publicly-traded options, all futures contracts, and all interest rate, currency and equity swaps, but would also include all employee stock options, all stock purchase contracts, and even a home heating oil contract.[56] The parties to all of these contracts would have to (somehow) value them at the end of the year, pay tax on any gain, and deduct any loss. The Camp proposal does exclude from the definition of derivative any financial instruments that are part of a “hedging transaction”[57] and, in a different proposal, Chairman Camp would expand the definition of a hedging transaction.[58]

There are several issues with which Chairman Camp will have to grapple as he refines his proposal in subsequent drafts. These issues, while important, should in no way detract from the overall strength of the proposal.

First, as Chairman Camp acknowledges, the proposal raises serious valuation issues because it applies to privately-held derivatives as well as publicly-traded ones.[59] Taxpayers are famous for claiming low values and the IRS for claiming high values of non-publicly traded property.

Second, marking-to-market non-publicly traded derivatives raises liquidity issues. It is unclear how taxpayers that hold non-publicly traded illiquid derivatives will pay the tax on their mark-to-market gains without cash and without any means to raise the cash. The proposal may thus effectively outlaw some legitimate business transactions.

The natural way to avoid these two issues would be to limit the proposal to publicly-traded derivatives and derivatives with respect to publicly-traded property. Publicly-traded derivatives and derivatives with respect to publicly-traded property can be valued easily, and are liquid. Publicly-traded for these purposes could be defined broadly to include all derivatives with respect to which fair market value can be reasonably determined. All other derivatives would remain on the realization system, but an interest charge might apply to gain on prepaid derivatives. Chairman Camp has requested comments on the valuation issue.[60]

Third, as discussed above, the proposal by its terms applies to employee stock options.[61] Stock options are widely used to compensate middle-income employees who usually cannot negotiate for cash compensation instead of stock options. Subjecting employees who hold stock options to mark-to-market treatment would require the employee to fund his or her tax liability from other sources. For these reasons, the treatment of employee stock options requires serious consideration. The technical explanation of Chairman Camp’s draft does not indicate that the application of the proposal to employee stock options was ever considered.[62] Because the proposal appears aimed at investors, speculators, and high-income individuals (but not middle-income employees), it would seem more appropriate to exclude employee stock options from the proposal.

Likewise, as mentioned above, the proposal applies to a stock purchase agreement that is expected to close within a reasonable time, and home heating oil and other consumer product contracts.[63] All contracts entered into by individuals that are not in connection with a business or for investment should be excluded, as should purchase agreements that are expected to close within a reasonably short period of time.[64]

Fifth, the proposal applies only to positions established after the end of this year.[65] A less generous grandfather provision may be appropriate. Perhaps all financial instruments that otherwise would qualify as a derivative would be subject to mark-to-market after five years. Otherwise, a mad rush would begin as taxpayers hurry to enter into long-dated derivatives that would be forever grandfathered from the proposal.

Sixth, the proposal does leave open some opportunities for taxpayers to create synthetic derivatives with partnerships and foreign corporations.[66] These loopholes will have to be closed. For example, assume that a taxpayer contributes $10 to a partnership and an investment bank contributes $90. The partnership then uses the $100 to buy publicly-traded XYZ stock and allocates all dividends, losses and the first $10 of gain to the investment bank, and all gain in excess of $10 to the taxpayer.[67] Economically, this transaction results in the taxpayer’s holding a synthetic option, but because the taxpayer does not hold a “derivative” (it holds a partnership interest and not an option), it appears that the taxpayer would not be subject to mark-to-market treatment on this synthetic option. An anti-abuse rule would require this taxpayer to mark-to-market its partnership interest.

Seventh, some clarifications are in order. The proposal defines derivative to include “any evidence of an interest in” a stock and a partnership interest, among others.[68] But that definition would seemingly include actual ownership, which clearly is not intended by the proposal. If the proposal remains limited to derivatives, the definition of derivative should be modified to clarify that it does not apply to ownership of actual stock or an actual partnership interest.

In addition, the proposal should make clear that except for the fact that unrealized gain or loss is recognized at the end of the year, the gain is ordinary gain or loss, and any loss is carried forward, the consequences for taxpayers of holding derivatives should remain the same. Thus, individuals should be subject to the new 3.8% Medicare tax on their net mark-to-market investment gains.[69] The proposal should not change whether a tax-exempt investor recognizes “unrelated business taxable income” and is taxable on its derivatives.[70] Likewise, the proposal should not change whether a foreigner is subject to tax by the United States on its derivatives.[71] Finally, the proposal should not exempt the United States shareholders of a “controlled foreign corporation” from tax with respect to the derivatives held by that corporation.[72] That is, if gain or loss on a derivative would have been “subpart F income”[73] of a controlled foreign corporation before the proposal was enacted (and therefore its United States shareholders would be subject to tax on their share of that gain), the mark-to-market gain should also be subpart F income.[74]

Finally, if enacted, the proposal would accentuate a most curious anomaly. A taxpayer who holds a forward contract on stock would have to mark-to-market the derivative and pay tax on all of her economic income at ordinary income rates.[75] But a holder of the underlying stock will avoid paying any income tax on his stock by simply holding it until he dies.  And so the Camp proposal is as significant for what it does as for what it doesn’t do: It doesn’t affect stockholders.

The ability of stockholders under our realization system to defer tax indefinitely on their economic income creates horizontal inequity with wage earners, who are taxable immediately on their economic income.  It also exempts significant wealth from any income tax.

The best way to achieve “horizontal equity” for wage earners (who are taxed on nearly all of their economic income) and entrepreneurs and investors (who are taxed on none), and raise hundreds of billions of dollars of new revenue over the next ten years without raising tax rates, hurting job growth, or affecting a single small business owner would be to enact a progressive system of mark-to-market taxation.

For individuals and married couples who earn more than $2.2 million in income, or own $5.7 million or more in publicly traded securities (representing the highest earning and wealthiest 0.1% of families), the appreciation in their publicly traded stock and securities (and derivatives with respect to those securities) would be “marked-to-market” and taxed annually as if they had sold their positions at year end, regardless of whether the securities were actually sold.[76]

The most serious challenge to a progressive system of mark-to-market taxation is the psychological concern about taxing “paper gains.”

Camp’s proposal is revolutionary but it does not address our tax system’s more fundamental horizontal equity issues. By shattering the psychological hurdle to taxing paper gains, however, Camp’s proposal offers hope that what may once have been considered impossible to enact is now possible: the transition to an economic model for the taxation of financial instruments.[77]

 

 


Preferred citation: David S. Miller, Toward an Economic Model for the Taxation of Derivatives and Other Financial Instruments, 3 Harv. Bus. L. Rev. Online 108 (2013), https://journals.law.harvard.edu/hblr//?p=3134.

* Partner, Cadwalader, Wickersham & Taft, LLP. The author wishes to thank his colleagues Shlomo Boehm, Kathryn Harrington, and Jason Schwartz for their comments.

[1] The NYSE share volume on October 3, 1913 (the date of the enactment of the federal income tax) was 223,344. Daily Share Volume in NYSE Listed Issues from 1900 through 1919, NYSE Euronext, http://www.nyse.com/marketinfo/stats/vol00-19.dat (last visited Feb. 27, 2013). In the first five months of 2012, the average daily trading volume of the NYSE was about 3.8 billion shares. Joe Light, Stock Market Loses Face, Wall St. J., May 29, 2012, at C1, available at http://online.wsj.com/article/SB10001424052702304065704577429111951625728.html.

[2] The stock market collapsed in 1907 and again on July 30, 1914. See Bankers Here Confer on War, N.Y. Times, July 31, 1914, http://query.nytimes.com/mem/archive-free/pdf?res=9404E0DA143EE033A25752C3A9619C946596D6CF.

[3] See Michael J. Graetz & Deborah H. Schenk, Federal Income Taxation: Principles and Policies 738 (6th ed. 2009) (“The Internal Revenue Code did not recognize the significance of compound interest until 1982 and even now uses compound interest concepts only in certain contexts.”).

[4] See, e.g., Fischer Black & Myron Scholes, The Pricing of Options and Corporate Liabilities, 81 J. Pol. Econ. 637 (1973); Robert C. Merton, Theory of Rational Option Pricing, 4 Bell J. Econ. & Mgmt. Sci. 141 (1973).

[5] See, e.g., Robert Murray Haig, The Concept of Income–Economic and Legal Aspects, in The Federal Income Tax (Robert Murray Haig ed., 1921); Henry C. Simons, Personal Income Taxation: The Definition of Income as a Problem of Fiscal Policy (1938).

[6] See I.R.C. § 1001 (2012).

[7] In Eisner v. Macomber, the Supreme Court held that stock dividends are not “income” within the meaning of the Sixteenth Amendment because they had not been realized and therefore could not be taxed by Congress without apportionment to the states. 252 U.S. 189 (1920). However, the Court subsequently discredited the reasoning of Macomber. See, e.g., Helvering v. Horst, 311 U.S. 112, 116 (1940) (stating that the realization requirement is “founded on administrative convenience”). Most commentators have unequivocally concluded that the realization requirement is merely an administrative—and not a constitutional—rule. See, e.g., David M. Schizer, Realization as Subsidy, 73 N.Y.U. L. Rev. 1549, 1576 & nn.108–10 (1998); Marvin A. Chirelstein, Federal Income Taxation 73 (11th ed. 2009) (“realization is strictly an administrative rule and not a constitutional, much less an economic, requirement of ‘income’”).

[8] In the second century, the astronomer Claudius Ptolemy succeeded in predicting the positions of the sun, moon, and the planets under a geocentric model of the heavens. His model was used for over 1,400 years. To explain and predict heliocentric planetary patterns in a geocentric model, Ptolemy’s planets traveled in a series of epicycles around the earth. But this alone was insufficient. To correct further, Ptolemy had the planets move closer and then further away from the earth, and even slow down and reverse in their orbits. See generally Ptolemy’s Almagest (G.J. Toomer trans., 1984) (translating Ptolemy’s treatise on astronomy into English).

[9] See Ways and Means Discussion Draft, H.R. ___, 113th Cong. § 401 (Jan. 23, 2013), available at http://waysandmeans.house.gov/uploadedfiles/leg_text_fin.pdf (discussing proposed section § 485(a)(1)).

[10] Graetz & Schenk, supra note 3, at 7.

[11] An Act to Reduce and Equalize Taxation, to Amend and Simplify the Revenue Act of 1918, and For Other Purposes: Hearings on H.R. 8245 Before the S. Comm. on Fin., 67th Cong. 51 (1921) (statement of Dr. T.S. Adams, Tax Adviser, Treasury Department).

[12] Id. at 51–52 (statement of Sen. Charles Curtis, Member, S. Comm. on Fin.).

[13] H.R Rep. No. 67-350, at 10 (1921); S. Rep. No. 67-275, at 14 (1921).

[14] See, e.g., I.R.C. § 1091 (2012).

[15] See Pub. L. No. 100-647, § 5075, 102 Stat. 3342, 3682 (1988); Pub. L. No. 106-554, § 401(d), 114 Stat. 2763, 2763A-649 (2000).

[16] See David M. Schizer, Scrubbing the Wash Sale Rules, 4 J. Tax’n Fin. Products 67, 71–76 (2003).

[17] Rev. Rul. 77-185, 1977-1 C.B. 48.

[18] Id.

[19] Id.

[20] Id.

[21] Id.

[22] Id.

[23] Columbia Law School Professor Michael Graetz has described a tax shelter as a “deal done by very smart people that, absent tax considerations, would be very stupid.” Lynnley Browning, How to Know When a Tax Deal Isn’t a Good Deal, N. Y. Times, Sept. 10, 2008, at SPG4, available at http://www.nytimes.com/2008/09/10/business/businessspecial3/10TAX.html?pagewanted=all.

[24] Section 1256 options are subject to tax at a rate equal to 60% of the long-term capital gains rate plus 40% of the short-term capital gains rate. I.R.C. § 1256 (2012).

[25] Today this subsidy amounts to $4.4 billion over five years. Joint Comm. on Tax’n, 112th Cong., Estimates of Federal Tax Expenditures for Fiscal Years 2011–2015, JCS-1-12, at 38 (2012).

[26] I.R.C. § 1092 (2012).

[27] See Tax Reform Act of 1984, Pub. L. No. 98-369, § 101, 98 Stat. 494, 616 (codified as amended in scattered sections of 26 U.S.C.).

[28] I.R.C. § 1256 (2012).

[29] Treas. Reg. § 1.1092(d)-2 (1995).

[30] Prop. Treas. Reg. §§ 1.263(g)-3(b), 3(e), 66 Fed. Reg. 4746, 4749–50 (Jan. 18, 2001).

[31] I.R.C. § 163(l) (2012) (enacted by American Jobs Creation Act of 2004, Pub. L. No. 108-357, § 845(a), (b), (d), 118 Stat. 1418, 1600–01 (2004)).

[32] See Allan Sloan, Passing the Smell Test?, Newsweek, Dec. 4, 1995, at 57, available at http://www.thedailybeast.com/newsweek/1995/12/03/passing-the-smell-test.html.

[33] Id.

[34] See I.R.C. § 1259 (2012).

[35] See id. § 1211.

[36] See id. §§ 1271–1273.

[37] See Treas. Reg. § 1.1275-4 (2013).

[38] See I.R.C. § 1258 (2012).

[39] See id. § 1260.

[40] See Prop. Treas. Reg. § 1.446-3(g)(6), 69 Fed. Reg. 8886 (Feb. 26, 2004).

[41] I.R.S. Notice 2004-52, 2004-2 C.B. 168.

[42] Treas. Reg. § 1.263(a)-4(d)(2)(i)(C)(7) (2004).

[43] See Prop. Treas. Reg. § 1.446-3(g)(6), 69 Fed. Reg. 8886 (Feb. 26, 2004).

[44] See id.

[45] See Lee A. Sheppard, News Analysis: Credit Default Swaps in Bankruptcy Court, 132 Tax Notes 323 (July 25, 2011).

[46] See David Kocieniewski, A Family’s Billions, Artfully Sheltered, N.Y. Times, Nov. 26, 2011, at A1, available at http://www.nytimes.com/2011/11/27/business/estee-lauder-heirs-tax-strategies-typify-advantages-for-wealthy.html?pagewanted=all; Jesse Drucker, Buffett-Ducking Billionaires Avoid Reporting Cash Gains to IRS, Bloomberg (Nov. 21, 2011), http://www.bloomberg.com/news/2011-11-21/billionaires-duck-buffett-17-tax-target-avoiding-reporting-cash-to-irs.html.

[47] Rev. Rul. 2003-7, 2003-1 C.B. 363.

[48] According to figures available at StructuredRetailProducts.com, the aggregate amount of SEC-registered notes (both listed and unlisted) in the US between 1/1/2003 and 12/31/2012 totaled $253,088 billion. See Wrappers Report, Structured Retail Products, http://structuredretailproducts.com/analysis/reports (last visited Mar. 6, 2013) (select “USA” in Select Database; then select “Calendar Year” and From “2003” To “2012” in Select Period; then select “Wrappers” in Select Report and include “non retail,” “leverage,” and “flow & others”; then select “USD” in Select Currency).

[49] See Treas. Reg. § 1.1275-4 (2013).

[50] See Ways and Means Discussion Draft, H.R. ___, 113th Cong. § 401 (Jan. 23, 2013), available at http://waysandmeans.house.gov/uploadedfiles/leg_text_fin.pdf (discussing proposed section 485(a)(1)). This description of the proposal is general and not comprehensive.

[51] See id. (discussing proposed section 485(a), (b)). The loss would not be a miscellaneous itemized deduction subject to limitations on deductibility.

[52] Id. (discussing proposed section 485(c)).

[53] Id. (discussing proposed section 486(a)).

[54] Id. (discussing proposed sections 486(b), (c)).

[55] Id. (discussing proposed section 485(e)(3)).

[56] See id. (describing proposed section 486). Home oil contracts constitute a derivative that must be marked-to-market under the Camp proposal.

[57] Id. (describing proposed section 486(f)).

[58] See id. § 402 (discussing proposed section 486, which would amend I.R.C. § 1221 (2012)).

[59] House Comm. on Ways & Means, Technical Explanation of the Ways and Means Committee Discussion Draft Provisions to Reform the Taxation of Financial Instruments 9 (Jan. 24, 2013), available at http://waysandmeans.house.gov/uploadedfiles/final_financial_products_discussion_dated_tomorrow.pdf [hereinafter Technical Explanation].

[60] House Comm. on Ways & Means, Overview of Ways and Means Tax Reform Discussion Draft: Financial Products 3 (Jan. 24, 2013), http://waysandmeans.house.gov/uploadedfiles/overview_of_wm_discussion_draft_financial_products.pdf (“The Committee recognizes that the discussion draft does not address several technical and policy issues that may need to be resolved in final legislation. The Committee invites comments on how to address such issues, in particular those related to: Valuing derivatives that would become subject to mark-to-market tax treatment.”).

[61] See Technical Explanation, supra note 59, at 8–9.

[62] See id. at 8–10.

[63] See Ways and Means Discussion Draft, H.R. ___, 113th Cong. § 401 (Jan. 23, 2013), available at http://waysandmeans.house.gov/uploadedfiles/leg_text_fin.pdf (discussing proposed section 486).

[64] Cf. I.R.C. § 1259(c)(2) (2012) (providing for an exception from a constructive sale if “the taxpayer enters into a contract for sale of any stock, debt instrument, or partnership interest which is not a marketable security . . . if the contract settles within 1 year after the date such contract is entered into”).

[65] See Ways and Means Discussion Draft, H.R. ___, 113th Cong. § 401(f) (Jan. 23, 2013), available at http://waysandmeans.house.gov/uploadedfiles/leg_text_fin.pdf .

[66] See id. § 401 (describing proposed section 486).

[67] See also Victor Fleischer, A Sensible Change in Taxing Derivatives, N.Y. Times (Feb. 7, 2013), http://dealbook.nytimes.com/2013/02/07/a-sensible-change-in-taxing-derivatives/ (“There are some additional problems with the legislation that need to be addressed. One is the tax treatment of compensatory stock options, which would be taxed on a mark-to-market basis under the proposal, but were probably not intended to be.”).

[68] See Ways and Means Discussion Draft, H.R. ___, 113th Cong. § 401 (Jan. 23, 2013), available at http://waysandmeans.house.gov/uploadedfiles/leg_text_fin.pdf (discussing proposed section 486(a)).

[69] See I.R.C. § 1411 (2012) (3.8% Medicare tax).

[70] See id. § 512 (defining “unrelated business taxable income”).

[71] See generally id. §§ 871, 881, 882 (describing taxation of nonresident alien individuals and foreign corporations).

[72] See generally id. § 957 (defining controlled foreign corporation).

[73] See id. § 952 (defining subpart F income).

[74] See id. § 951(a)(1)(A) (requiring United States shareholders of controlled foreign corporations to include in income their pro rata share of the corporation’s subpart F income for the year).

[75] The highest marginal rate of 39.6% plus the 3.8% Medicare tax is 43.4%. Id. §§ 1, 1411. However, the new Pease limitations, by denying deductions equal to 3% of adjusted gross income in excess of a threshold, have the effect of increasing rates by another 1.302% ((39.6% + 3.8%) x 3%). See Frank Armstrong III, Pease Limitation Puts a Lid on Itemized Deductions for Wealthy Folks, Forbes.Com (Jan. 9, 2013), http://www.forbes.com/sites/greatspeculations/2013/01/09/pease-limitation-puts-a-lid-on-itemized-deductions-for-wealthy-folks/.

[76] See David S. Miller, A Progressive System of Mark-to-Market Taxation, Tax Analysts Special Report, Tax Notes, 1054 n.53 (Nov. 21, 2005), available at http://www.cadwalader.com/assets/article/120505MillerTaxNotes.pdf; David S. Miller, A Progressive System of Mark-to-Market Taxation, 121 Tax Notes 213, 213 (Oct. 13, 2008), available at http://www.cadwalader.com/assets/article/101308MillerTaxNotes.pdf; David S. Miller, The Zuckerberg Tax, N.Y. Times, Feb. 8, 2012, at A27, available at http://www.nytimes.com/2012/02/08/opinion/the-zuckerberg-tax.html.

[77] See Chris Sanchirico, The Investment Tax Plan: Implications for Lower Rates on Capital Gains?, The Christian Science Monitor (Jan. 31, 2013), http://www.csmonitor.com/Business/Tax-VOX/2013/0131/The-investment-tax-plan-implications-for-lower-rates-on-capital-gains. Camp’s proposal “implicitly challenges our most basic and firmly held beliefs about why we tax investment gains the way we do.” Id.

Filed Under: Derivatives Regulation, Featured, Home, U.S. Business Law, Volume 3

March 11, 2013 By wpengine

From Reaction to Prevention: Product Approval as a Model of Derivatives Regulation

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Saule T. Omarova*

Introduction: Dilemmas of Regulatory Reform

The global financial crisis of 2008 underscored the importance of reducing and managing systemic risk in derivatives markets. Even though the crisis originated in the U.S. subprime mortgage market, over-the-counter (OTC) derivatives significantly contributed to pre-crisis accumulation of excessive risk and hidden leverage in the global financial system.[1] Derivatives offer private counterparties an unprecedented degree of flexibility and freedom to achieve desired outcomes by unbundling, reassembling, and trading financial risk. They may, and often do, function as a socially beneficial mechanism of prudent risk management and liquidity provision.[2] At the same time, by removing some of the traditional constraints on speculative trading—such as the need to purchase, hold, or physically move underlying assets—derivatives have fundamentally altered the nature and dynamics of financial investment and intermediation. By the mid-2000s, increasingly complex and opaque derivatives had become the key tool of financial speculation and regulatory arbitrage, ultimately leading the financial system to the brink of collapse.[3]

Not surprisingly, the need to update and strengthen regulatory oversight of derivatives markets has emerged as one of the key themes in post-crisis financial regulation reform. The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the Dodd-Frank Act) contains a wide range of measures designed to increase transparency in derivatives trading and to encourage better risk management on the part of private market participants.[4] The key element of the new statutory scheme is the mandatory central clearing of standardized derivatives and trading through regulated exchanges and swap execution facilities.[5] The statute also mandates public reporting of swap transactions[6] and introduces new regulatory categories of financial actors—swap dealers and major swap participants—that must comply with special business conduct, capital, and margin rules.[7]

The extent to which these reforms are likely to reduce systemic risk in practice remains to be seen.[8] Fundamentally, however, the Dodd-Frank Act falls short of radically reshaping the structure or operation of derivatives markets. It does not impose direct, targeted regulatory restraints on the levels of risk, complexity, or leverage in the OTC derivatives market.[9] Instead, the new law seeks to restrain potential risks posed by derivatives only indirectly, mainly through enhancing informational flow and rationalizing the clearing and settlement process for sufficiently standardized instruments. It leaves intact the monopoly of private actors on deciding which products—and, accordingly, risks—are traded in derivatives markets. In that sense, the Act’s focus is inherently reactive and retrospective rather than proactive and prospective. Ultimately, the new law fails to address the key policy question: how much risk in derivatives markets is too much for the public to bear, and how can we prevent such socially harmful risk from entering the financial system in the first place?

A Paradigm of Prevention: Approval Regulation

This Article explores one possible way to answer this fundamental question. It outlines the rough contours of a regulatory scheme based on mandatory pre-market government licensing of complex financial instruments, including derivatives. An envisioned model of product approval regulation explicitly aims to control the amount and types of risk being introduced into the financial system. In that sense, it is a true gatekeeping mechanism, a form of ex ante regulation of systemic risk in financial markets.[10]

Generally, approval regulation can be defined as a regime in which “government entities exercise discretion over whether the firm or product can enter the market, such that firms must provide an empirical case for admission that the regulator must accept if legal market entry is to be granted.”[11] Product approval has long been the model of pharmaceutical drug regulation in the United States and has recently been introduced in the European Union for chemicals regulation.[12] A similar system of pre-trading “contract designation” also existed in the area of the U.S. commodity futures regulation prior to 2000.[13] Potential extension of approval regulation to a broad range of financial products became a subject of academic discussion in 2008-09, in the context of the debate on the creation of a new consumer financial protection agency with the power to pre-approve financial products to ensure they are “safe” for consumers.[14]

Approval regulation, however, may also serve as a potentially effective mechanism for controlling systemic financial risk, not just the risk to individual consumers.[15] Of course, shifting the focus of the proposed scheme toward systemic concerns—socially unproductive levels of complexity, leverage, speculation, regulatory arbitrage, and interconnectedness in financial markets—complicates the task of designing it. A rigorous product approval regime can inadvertently limit the ability of financial firms to develop and market potentially beneficial financial instruments and impede socially useful financial innovation, which may have serious consequences for long-term economic growth.[16] In this context, it becomes critical to articulate, in clear and unambiguous terms, the normative basis on which the new scheme would operate. Not only does this task involve making potentially difficult policy choices and trade-offs, but it also elevates the importance of drawing clear definitional and procedural lines, neither of which is an easy undertaking in the world of derivatives.

Regulatory Objective: Reducing Strategic Complexity

As the recent crisis demonstrated, numerous factors contribute to a systemic market failure. In designing a product approval regime, however, it is important to define the scheme’s normative focus as clearly as possible. Which of the well-documented “evils” in modern financial markets should be designated as the primary target of ex ante regulatory intervention? The laundry list of plausible candidates includes, at a minimum, excessive speculation, leverage, regulatory arbitrage, and complexity.[17] Of course, truly effective regulation should target all of these phenomena in order to prevent an unsustainable level of risk accumulation in the financial system. However, for the purposes of providing clear policy guidance to regulators administering a product approval scheme, sharpening its policy focus may be a more effective strategy.

One potential approach would be to structure the new regulatory regime to target primarily and explicitly what I call strategic complexity in financial markets: constant introduction of new complex financial instruments into the market, regardless of actual demand or true economic need for such instruments.[18] In general, increasing complexity of financial instruments and institutional structures through which they are traded is one of the key sources of systemic financial risk.[19] What is particularly insidious in this respect is that much of that risk-generating complexity results from purely strategic efforts of dealers and market-makers—financial intermediaries that structure, sell, and deal in complex financial instruments—seeking short-term, monopoly-like rents.[20] Dealers derive the highest profits from being the first to design and sell to clients a new financial instrument that is perceived as offering some unique benefits to investors, mostly by enhancing their ability to engage in speculation and arbitrage, and commands a high premium. Once a new product becomes commoditized, the original dealer loses its ability to extract monopolistic rents and seeks to introduce the next innovation to recapture lost rents, without regard to any natural demand for such a product in the marketplace.[21] In the course of this socially inefficient over-innovation, dealer institutions originate, distribute, and amplify financial risk. That, in turn, enables other market participants to make increasingly risky and levered speculative bets, expands intra-market linkages and interconnectedness, and preemptively defeats regulators’ efforts to exercise effective oversight of the financial system.

It makes intuitive sense, therefore, that limiting financial institutions’ ability to over-supply unnecessarily complex financial products should substantially decrease levels of speculative trading, leverage, interconnectedness, and systemic fragility. The most effective method of achieving this goal is to insert regulatory controls at the point of product development, before financial intermediaries introduce the risk into the system. Under this regime, the regulatory agency would act as a gatekeeper and its primary task would be to vet all new financial products for indicia of strategic complexity and other socially undesirable risk attributes.[22]

Regulatory Mechanism: The Three-Part Product Approval Standard

The core element of a product approval scheme is the substantive standard for determining whether a particular product should be allowed to enter the market. Fashioning a comprehensive and precise set of standards for licensing derivatives and other financial products is a difficult task. Nevertheless, it is possible to envision key substantive and procedural principles of a viable product approval mechanism. Inevitably, this is more of a thought experiment than a legislative blueprint.

The key aim of the product licensing review should be to evaluate each relevant financial instrument from functional, institutional, and policy perspectives. Regulatory approval should be granted only if the application meets a three-part statutory standard: (1) an “economic purpose” test, which would place the burden of proving commercial and social utility of each proposed financial instrument on the financial institutions seeking approval; (2) an “institutional capacity” test, which would require a review of the applicant-firm’s ability to monitor and manage the risks of the proposed product effectively; and (3) a “systemic effects” test, which would require a finding that approval of the proposed product does not pose an unacceptable risk of increasing systemic vulnerability and does not raise significant public policy concerns.

The “Economic Purpose” Test

First, the financial institution would have to make an affirmative showing that the proposed financial instrument has a bona fide economic purpose that promotes productive enterprise and does not merely provide another means of financial speculation, leverage, or regulatory arbitrage. The goal of the product approval regime is to discourage financial institutions from creating and marketing complex financial instruments, where the benefits of such complexity for the economy and broader society do not outweigh potential increase in systemic risk.

To meet this test, an applicant-firm will have to (1) identify the intended market for the proposed financial product and describe (with sufficient specificity) potential users; (2) show that the product will fulfill a specific business need of potential product users, which existing financial products fail to fulfill; and (3) demonstrate that this legitimate business need significantly outweighs any potential uses of the product for speculative investment or regulatory arbitrage as the core motivation for the product user (or the applicant firm) to enter into the proposed transaction.[23]

The economic purpose test is essentially a “facts-and-circumstances” inquiry.[24] The applications would have to describe the target market for the product and the intended economic purpose of the product in reasonably specific terms, in order to show a relatively direct and meaningful link between the proposed financial instrument and some productive economic activity outside the confines of financial markets.[25] Applicant-firms would be required to monitor on an ongoing basis the markets for their approved products and report any significant changes in the market composition and uses of the relevant products, as these changes may alter considerations on which the original approval grant was based.[26]

In effect, financial institutions will have to provide complete ongoing disclosure and analysis of their dealing and market-making activities. This burden-shifting mechanism would begin correcting the informational asymmetries between regulators and industry and the current incentive structure that encourages socially sub-optimal risk-taking by financial market actors.

The “Institutional Capacity” Test

The second part of the statutory standard would require the applicant to demonstrate its internal organizational, operational, and financial capacity to monitor and manage potential risks the proposed product poses to the institution’s own financial health, as well as to the financial well-being of the product’s users and overall market stability.

To meet this test, the applicant would have to satisfy certain capital adequacy or similar requirements limiting its ability to incur leverage.[27] Additional factors to be considered may include the firm’s overall business and risk profile; the relationship between the proposed activity and the rest of the firm’s business and resources (including human and technological resources); internal systems of risk management and regulatory compliance; previous regulatory and compliance record; and the history of enforcement against the firm or its affiliated entities. It is also important to review and evaluate whether the firm has established effective risk management policies and procedures designed specifically for the proposed activity.

The inquiry at this point should not be limited to the firm’s ability to handle the economic demands of dealing in the specific product. It is just as critical to assess how the proposed activity may alter the firm’s economic incentives and overall business strategy, and whether or not such a change creates potential conflicts of interest, poses reputational risks to the firm, or raises significant concerns about broader market integrity.[28] To put it simply, the key question has to be, “Do we want this particular institution to trade and deal in this particular product?”

The “Systemic Effects” Test

Finally, the applicant-firm will also have to demonstrate that the proposed product does not pose potentially unacceptable systemic risk or is otherwise likely to increase the vulnerability of the financial system. This intentionally broad requirement gives the regulator statutory authority to consider a wide variety of potentially relevant factors and public policy considerations that may not be directly included in the description of the product or the immediate market needs. Many existing statutes mandate that financial regulators exercise their discretion only if doing so is “in the public interest.”[29] This aspect of the product approval process is designed to allow for this type of deliberation, where the applicant-firm bears the burden of proving that the financial instrument it seeks to market is not likely to have a negative impact on broader socio-economic policies and political goals.[30]

Implementing the Mechanism: Operational Design Challenges

This cursory outline of a product approval mechanism raises many legitimate questions about the proper scope, feasibility, and potential negative consequences of instituting such an intrusive regulatory scheme. While it is impossible to answer all of these questions in this short Article, it is useful to sketch out some of the key challenges posed by this proposal.

To function effectively, a product approval mechanism must be embedded in a properly designed regulatory structure. Many operational details of such a structure would require serious thought. Perhaps the most critical—and most difficult—task in this respect is delineating the overall scope of the scheme and defining which classes of financial products and transactions should be subject to regulatory pre-approval. While an over-inclusive definition may have an unnecessary chilling effect on socially beneficial innovation, an under-inclusive definition may allow for the excessive build-up of systemic risk in financial markets and thus undermine the efficacy of the entire regime.

Complex trading strategies and sophisticated structuring techniques raise an even more difficult question: What constitutes a “product” that would require a separate regulatory approval under the new regime?[31] Thus, one of the critical tasks in designing the new regulatory regime is to develop a set of criteria for determining when a particular instrument has features unique enough to make it a separate “product.” As a first approximation, that list of factors should include key terms related to payment and other significant rights and obligations of the counterparties, the intended uses and target markets of the instrument, and the nature of assets underlying the instrument. A significant change in any of these terms would require the financial institution to apply for a separate regulatory approval.

Finding a workable solution to these definitional problems—where and how exactly to draw the lines between separate “products” and which of those “products” should be subject to mandatory licensing—may be the key to the feasibility of the proposed scheme.[32] Among other things, these choices would determine the volume of deals to be reviewed and approved by the regulator under the new regime. After all, the viability of any regulatory model depends on the agency’s resources and ability to manage the process in practice.

Beyond these definitional problems, numerous questions arise with respect to structuring the process of approval, assigning regulatory jurisdiction, and enforcing compliance. Developing these operational details requires careful balancing of competing considerations of procedural fairness and efficiency, regulatory flexibility and regime integrity, technical expertise and public accountability.[33] These difficulties are hardly insurmountable, nor are they unique to this proposal. In any event, envisioning an operational product approval scheme is a valuable intellectual exercise for purposes of shaping the future of regulatory reform.

Conclusion: Redefining What Is Possible

This Article explored the prospect of a fundamental shift in derivatives regulation and advocated an explicitly anticipatory approach to reducing systemic risk in the financial sector. The proposed model of ex ante derivatives regulation does not prohibit any financial activities. It merely imposes the duty to provide information necessary for evaluating potential risks and benefits of a specific financial product on the financial institution seeking to market it. If properly designed and implemented, this regulatory approval process would provide a mechanism for ensuring that financial innovation, in fact, advances productive enterprise in the real economy and offers real public benefits.

As discussed above, executing this idea will likely involve resolving various technical and operational challenges. Because it calls for a radical change in the existing regulatory philosophy, this proposal is also bound to generate criticisms on other grounds. To some, product approval may appear too blunt a tool, liable to cause more harm than good by stifling financial innovation and driving financial activities abroad. Others may see it as unacceptably paternalistic “command-and-control” regulation. Finally, many may doubt the presence of political will to take on such bold and controversial reforms.

This Article does not purport to provide answers to every question and dispel every doubt. It may very well prove too difficult to design and implement a comprehensive and effective mandatory product approval scheme for derivatives (or any other financial products) in practice. Nevertheless, it is critical to give this seemingly radical proposal a full, open-minded consideration as a potentially superior alternative to the current, ex post regulatory approach. At the very least, expanding the range of plausible reform options should lead to more meaningful academic discussions and better informed policy decisions. By making a preliminary case for product approval as a potentially plausible model of derivatives regulation, this Article seeks to enhance our chances of getting it right next time.

 

 


Preferred citation: Saule T. Omarova, From Reaction to Prevention: Product Approval as a Model of Derivatives Regulation, 3 Harv. Bus. L. Rev. Online 98 (2013), https://journals.law.harvard.edu/hblr//?p=3111.

* Assistant Professor at the University of North Carolina at Chapel Hill School of Law.

[1] See, e.g., Lynn A. Stout, Derivatives and the Legal Origin of the 2008 Credit Crisis, 1 Harv. Bus. L. Rev. 1 (2011); Mark J. Roe, The Derivatives Market’s Payment Priorities as Financial Crisis Accelerator, 63 Stan. L. Rev. 539 (2011).

[2] See Kimberly D. Krawiec, More than Just “New Financial Bingo”: A Risk-Based Approach to Understanding Derivatives, 23 J. Corp. L. 1, 7–8, 10 (1997); Roberta Romano, A Thumbnail Sketch of Derivative Securities and Their Regulation, 55 Md. L. Rev. 1, 5 (1996).

[3] See Stout, supra note 1, at 22–31.

[4] Dodd-Frank Wall Street Reform and Consumer Protection Act, Pub. L. No. 111-203, 124 Stat. 1376 (2010).

[5] Id. § 723.

[6] Id. §§ 727–30.

[7] Id. § 731.

[8] Much of the academic debate in this area focuses on the ability of derivatives clearinghouses to fulfill their risk-reducing role. See, e.g., Yesha Yadav, The Problematic Case of Clearinghouses in Complex Markets, 101 Geo L. J. 387, 412–20 (2013); Adam J. Levitin, Response: The Tenuous Case for Derivatives Clearinghouses, 101 Geo L. J. 445, 463–66 (2013).

[9] Two key provisions in the Dodd-Frank Act attempt to impose limits on derivatives activities of banking organizations: the Volcker Rule that bans banking organizations from proprietary trading, and the “swap push-out” rules that prohibit insured depository institutions from conducting equity and commodity derivatives business. See Dodd-Frank Act §§ 619, 716. Yet, for reasons too complex to be elaborated in this brief Article, there is little hope that, as implemented, these provisions will significantly reshape derivatives markets.

[10] For a more extensive and detailed elaboration of the proposal outlined in this Article, see Saule T. Omarova, License to Deal: Mandatory Approval of Complex Financial Products, 90 Wash. U. L. Rev. 63 (2012).

[11] Daniel Carpenter & Michael M. Ting, A Theory of Approval Regulation 2 (Feb. 10, 2004) (unpublished manuscript), http://people.hmdc.harvard.edu/~dcarpent/endosub-20040214.pdf. Approval regulation differs from the classic “regulation of entry” model that typically sets forth purely procedural conditions on market entry, such as licensing fees.

[12] Noah M. Sachs, Rescuing the Strong Precautionary Principle from its Critics, 2011 U. Ill. L. Rev. 1285, 1298–99 (2011).

[13] For a discussion of these three examples of approval regulation, see Omarova, supra note 10, at 89–113.

[14] See Oren Bar-Gill & Elizabeth Warren, Making Credit Safer, 157 U. Pa. L. Rev. 1 (2008); J. E. Stiglitz, The Financial Crisis of 2007/2008 and its Macroeconomic Consequences 29–30 (2008) (unpublished paper presented at meeting on Financial Markets Reform of the Initiative for Policy Dialogue Task Force), available at http://www2.gsb.columbia.edu/faculty/jstiglitz/download/papers/2008_Financial_Crisis.pdf; Daniel Carpenter, Particulars of a Financial Product Safety Commission, in The Tobin Project: Considering a Financial Product Safety Commission 8 (May 2009) available at http://people.hmdc.harvard.edu/~dcarpent/finreg/FPSC-Tobin.pdf. Although born of this debate, the Bureau of Consumer Financial Protection established under the Dodd-Frank Act does not have direct product-licensing authority.

[15] This idea is beginning to gain some recognition among academics. Professors Eric Posner and Glen Weyl recently proposed to set up a regulatory agency with the power to approve new financial products if they pass the “social utility” test that focuses on whether, based on a straightforward quantitative market analysis, the product would likely be used more often for insurance than for gambling. See Eric A. Posner & E. Glen Weyl, An FDA for Financial Innovation: Applying the Insurable Interest Doctrine to 21st-Century Financial Markets, 107 Nw. U. L. Rev. (forthcoming 2013), available at http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2010606&rec=1&srcabs=1995077&alg=1&pos=1.

[16] The latest crisis, however, demonstrated the many dangers of unrestrained financial innovation. See, e.g., Margaret M. Blair, Financial Innovation, Leverage, Bubbles, and the Distribution of Income, 30 Rev. Banking & Fin. L. 225 (2010).

[17] I deliberately leave aside a host of other potentially important factors—including greed, incompetence, and regulatory capture—because a product approval scheme cannot directly remedy these problems. If successful, however, a new regime may significantly alter, or counteract negative effects of, behavior causing these and other problems.

[18] See Omarova, supra note 10, at 73.

[19] For scholarly analyses of complexity in financial markets and its implications for systemic stability and efficiency, see Steven L. Schwarcz, Regulating Complexity in Financial Markets, 87 Wash. U. L. Rev. 211 (2010); Dan Awrey, Complexity, Innovation, and the Regulation of Modern Financial Markets, 2 Harv. Bus. L. Rev. 235 (2012); Henry T. C. Hu, Too Complex to Depict? Innovation, “Pure Information,” and the SEC Disclosure Paradigm, 90 Tex. L. Rev. 1601 (2012). See also Omarova, supra note 10, at 68–71.

[20] See Awrey, supra note 19, at 258–67; Omarova, supra note 10, at 72–73.

[21] See Awrey, supra note 19, at 263–65. In effect, dealers manufacture demand by offering clients new ways to increase their returns.

[22] This is in not to say that complexity is the only cause of systemic risk. Strategic complexity is a proxy for a cluster of risk-generating phenomena: it functions as a corollary for excessive speculation, over-leveraging, and regulatory arbitrage. It may also be easier (although by no means easy) to operationalize a regulatory scheme specifically focused on complexity of financial products, as opposed to their speculative potential or effect on the leverage in the financial system.

[23] In effect, the proposed test would reverse the currently dysfunctional concept of cost-benefit analysis of financial services regulation as a more risk-based and socially conscious cost-benefit analysis of financial services. In contrast to the current system, the proposed approach would allocate the duty to produce information necessary to conduct such analysis on the party that has full access to such information. For a critical examination of the current system of regulatory cost-benefit analysis, see Nicholas Bagley & Richard L. Revesz, Centralized Oversight of the Regulatory State, 106 Colum. L. Rev. 1260 (2006); Daniel A. Farber, Rethinking the Role of Cost-Benefit Analysis, 76 U. Chi. L. Rev. 1355 (2009).

[24] This is one of the key differences between the approval standard envisioned here and the quantitative market analysis of “social welfare” proposed by Posner & Weyl, supra note 15, at 16–19.

[25] This requirement raises many difficult questions about drawing the line between legitimate hedging and socially useless speculation. For a fuller discussion of some of these difficulties, and potential ways to solve them, see Omarova, supra note 10, at 116–20.

[26] This would enable the regulators to react in a timely manner when familiar financial instruments begin morphing into something different in terms of their functions and risk profile. The pre-crisis transformation of traditional residential mortgages and relatively straightforward mortgage-backed securitizations into a complex form of financial speculation provides an example of such dynamics. See Adam J. Levitin & Susan M. Wachter, Explaining the Housing Bubble, 100 Geo L. J. 1177 (2012).

[27] Importantly, regulators may require a (significantly) higher additional capital buffer to support the specific proposed financial transaction and related market activities.

[28] One example highlighting the importance of assessing this type of risk both to the firm’s reputation and to the broader market integrity is Goldman Sachs’ infamous “Big Short” strategy in early 2007. One of the major CDO originators, Goldman Sachs accumulated a large short position in mortgage-backed assets it was aggressively securitizing and marketing at the same time. See U.S. Senate Permanent Subcomm. on Investigations, Wall Street and the Financial Crisis: Anatomy of Financial Collapse 376–636 (2011), available at http://www.hsgac.senate.gov/subcommittees/investigations/reports.

[29] See, e.g., 12 U.S.C. § 371c(f)(2) (2012) (authorizing federal bank regulators to grant exemptions from the statutory limitations on banks’ transactions with affiliates if, among other things, the regulators find such exemptions to be “in the public interest”); Id. § 1843(a) (authorizing the Board of Governors of the Federal Reserve System to extend the two-year grace period for new bank holding companies to comply with the statutory prohibitions on non-banking investments if, in the Board’s judgment, “such an extension would not be detrimental to the public interest”). There are numerous examples of similar provisions in federal banking statutes.

[30] A quintessential example of a financial product banned on public policy grounds are terrorism futures, conceived in 2003 by the Pentagon as a market-based predictor of the level of risk posed by terrorist attacks. Justin Wolfers & Eric Zitzewitz, The Furor Over ‘Terrorism Futures,’ Wash. Post, July 31, 2003, at A19. Congress discarded this idea on public policy grounds. In 2011, the CFTC adopted a rule prohibiting the listing and trading of contracts referencing “terrorism, assassination, war, gaming, or an activity that is unlawful under any State or Federal law.” 17 C.F.R. § 40.11(a)(1) (2012).

[31] For example, under a well-functioning regime, a financial institution should not be able to apply for blanket pre-approval of all “swaps” or “equity swaps” and then proceed to structure and market a wide variety of such instruments with different risk profiles.

[32] For a more detailed discussion of potential solutions to these definitional problems, as well as other design issues, see Omarova, supra note 10, at 123–31.

[33] See id. at 131–35.

Filed Under: Derivatives Regulation, Featured, Home, U.S. Business Law, Volume 3

February 8, 2013 By wpengine

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://journals.law.harvard.edu/hblr//?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/87/2011/01/1_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.

Filed Under: Energy, Featured, Home, U.S. Business Law, Updates, Volume 3 Tagged With: Disclosure, Energy, Front Page

January 4, 2013 By wpengine

Sixth Circuit Pushes Back on EPA Oil and Gas Source Aggregation Under the Clean Air Act

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William Bumpers and Paulina Williams†

On August 7, 2012, the United States Court of Appeals for the Sixth Circuit (Sixth Circuit) issued an opinion that has significant Clean Air Act (CAA) regulatory implications for oil and gas development projects. In Summit Petroleum Corp. v. EPA, the court vacated an Environmental Protection Agency (EPA) determination that Summit Petroleum Corporation’s natural gas sweetening plant and sour gas production wells spread over forty-three square miles constituted a single stationary source for CAA permitting purposes.[1] The permitting requirements for projects like compressor stations and sweetening plants often determine whether such projects are feasible because of the timing and cost associated with such requirements. Whether New Source Review (NSR) air permitting requirements apply to a particular project sometimes depends on whether multiple emissions sources must be combined or “aggregated” and treated as a single source. The Summit Petroleum case is encouraging for oil and gas developers whose operations are often spread over substantial areas, though EPA indicates it does not intend to extend the decision’s reach beyond the Sixth Circuit at this time.[2]

A.            Air Permitting Overview

The NSR air permitting program under the CAA requires any major source or major modification[3] to obtain a permit prior to beginning construction.[4] Obtaining a permit can be expensive and the process from application submittal to permit issuance often takes years. Stringent controls may be required and, if the project is located in a “non-attainment area”[5] for a relevant pollutant, project emissions may have to be offset by emission reductions elsewhere.[6] Further, the 1990 CAA Amendments created a national permit system that requires “major sources”[7] of air pollution to obtain Title V operating permits that identify all of the air quality-related “applicable requirements” that govern the source.[8] Title V permit holders must self-report all deviations from the permit’s applicable requirements and, on an annual basis, certify continuous compliance with those requirements for which the permit holder has not reported a deviation.[9]

In contrast, if aggregation is not required, the air emissions associated with the construction of oil and gas wells and their related compressor stations and other ancillary facilities often could be authorized using a simple permit requiring the operator to notify the regulatory authority prior to commencing construction.[10] Because the consequences of major source status under both the NSR and Title V programs can be so burdensome, determining whether a given project will constitute a major source is critical to project development.[11]

B.            Regulatory Framework

Federal NSR regulations define a major stationary source as any building, structure, facility or installation that emits or may emit a regulated NSR pollutant.[12] The regulations further define a “building, structure, facility or installation” for source and emissions accounting purposes.[13] EPA focuses on three factors found in the definition: (1) whether the activities belong to the same industrial grouping; (2) whether the activities are located on one or more contiguous or adjacent properties; and (3) whether the activities are under common control.[14] In applying these criteria, EPA, state, and local permitting authorities are guided by the directive in Alabama Power Co. v. Costle[15] to apply the “common sense notion of a plant.”[16]

While the issues of “industrial grouping”[17] and “common control”[18] are replete with nuance, it is the concept of “adjacent” properties that has been the focus in the oil and gas industry and the subject of substantial controversy.[19]

C.            Regulatory History

When EPA initially promulgated rules implementing the PSD program, it did not specify the distance between facilities that would qualify those facilities for separate permitting consideration.[20] Specifically, the preamble to the 1980 PSD rules provides:

EPA has stated in the past and now confirms that it does not intend “source” to encompass activities that would be many miles apart along a long-line operation. For instance, EPA would not treat all of the pumping stations along a multistate pipeline as one “source.” EPA is unable to say precisely at this point how far apart activities must be in order to be treated separately. The Agency can answer that question only through case-by-case determinations.[21]

Although EPA was unwilling at the time to specify a distance within which sources would be aggregated, it noted that activities separated by twenty miles are likely too far apart to be considered a single source.[22]

In this early guidance and in the 1980 preamble, EPA rejected the idea of looking beyond geographic proximity to factors like functional interrelatedness or interdependence. Nevertheless, EPA determinations over the years have held that interconnected operations separated by distances of 3.7 miles, 6 miles, and, in one extreme case, 21.5 miles, should be combined as a single source for permitting purposes.[23] By the mid- to late-1990s, EPA commonly gave more weight to the functional interrelatedness or interdependence of operations than the physical separation between facilities in making source determinations.[24]

Little of this evolving EPA guidance on adjacency in source determinations involved the upstream oil and gas sector. However, in the mid-2000s, states and environmental non-governmental organizations (NGOs) began to shift their attention further upstream to emissions from the oil and gas sector.[25] EPA under President George W. Bush released a guidance memorandum on source determinations directed specifically at the upstream oil and gas sector. [26] Issued in 2007 and titled “Source Determinations for Oil and Gas Industries,” this document became known as the “Wehrum Memo” after its author, William Wehrum, then Acting Assistant Administrator in EPA’s Office of Air and Radiation.[27]

According to the Wehrum Memo, interconnected sources could be counted as separate minor sources for NSR and Title V purposes if the sites were under common control, but located more than a quarter-mile from each other.[28] Because it made proximity the determining factor and established, for the first time, a precise distance (a quarter-mile) above which sources would be considered separate, the Wehrum Memo was assailed by environmental NGOs and certain states.[29]

In 2009, after President Obama’s inauguration, Gina McCarthy, the new Assistant Administrator for EPA’s Office of Air and Radiation, issued a memorandum that officially withdrew the Wehrum Memo.[30] The “McCarthy Memo,” as it came to be known, expressly rescinded the Wehrum Memo because of its emphasis on geographic proximity in oil and gas sector source determinations.[31] The McCarthy Memo noted that source aggregation determinations for the oil and gas industry must be made on a case-by-case basis based on an analysis of the three fundamental criteria: common control, industrial grouping, and whether the sources are “contiguous or adjacent.”[32] In withdrawing the Wehrum Memo, the McCarthy Memo made clear that EPA considered it possible, as it had prior to 2007, for activities located more than a short distance away to be aggregated based on an evaluation of the three factors.[33]

The withdrawal of the Wehrum Memo caused as much controversy in oil and gas circles as its issuance did among environmental NGOs.[34] The issue of functional interrelatedness and interdependence as a means of determining adjacency has been a key issue in challenges to upstream source aggregation decisions by both industry and environmental NGOs. Until recently, the collective results of these challenges were mixed.[35] This has spurred challenges in state and federal court and, in at least one example, inspired an environmental NGO to side-step the Title V objection process and file suit directly against an operator under the CAA’s citizen suit provisions.[36]

D.            Summit Petroleum Corporation v. EPA

Against this backdrop, on August 7, 2012, the Sixth Circuit ruled in Summit Petroleum Corporation v. EPA that EPA could not base adjacency in source determinations on anything but geographical proximity.[37] EPA had determined, pursuant to a request from Summit Petroleum and the Michigan Department of Environmental Quality, that Summit Petroleum’s facilities should be aggregated because they were “truly interrelated” and therefore adjacent.[38] EPA relied on the McCarthy Memo to support its determination that adjacency could exist despite lack of physical proximity.[39]

The Sixth Circuit considered that the dictionary definition and plain meaning of “adjacent” requires proximity,[40] that case law supported the idea that adjacency relates only to physical proximity,[41] and that EPA’s own regulatory history did not support the use of a relatedness test.[42] The court concluded by remanding the determination to EPA to be made based on “the proper, plain-meaning application of the requirement that Summit’s activities be aggregated only if they are located on physically contiguous or adjacent properties.”[43] While physical proximity is the touchstone of the analysis, just how proximate is sufficient remains to be seen.

Judge Moore, in dissent, argued that EPA’s interpretation of the term “adjacent” was entitled to deference and that examining functional interrelatedness provides context for determining if facilities are sufficiently proximate to be considered adjacent.[44] Judge Moore expressly contended that the remand does not require EPA to reach a particular result, but only to provide a justification for its decision consistent with the majority opinion.[45] Elsewhere, Judge Moore also asserted that, although not a fact relied on by EPA, the wells all draw from the same, contiguous gas field.[46]

E.             Similar Aggregation Arguments at the State Level

The debate in Summit Petroleum mirrors the clear split between the Pennsylvania state permitting authority and EPA Region III. State agencies conduct most air permitting pursuant to EPA-approved programs, but EPA can comment and, with more teeth, can issue objections to Title V permits.[47] In October 2011, the Pennsylvania Department of Environmental Protection (PADEP) issued guidance on source aggregation titled “Guidance for Performing Single Stationary Source Determination for Oil and Gas Industries” (PADEP Guidance).[48] Whereas the McCarthy Memo was the result of a change from Republican to Democratic control of the EPA, the PADEP Guidance resulted from a gubernatorial race that saw the Republican Party unseat the incumbent Democrat.[49]

Conflict between EPA and PADEP related to the guidance was inevitable. The PADEP Guidance, like EPA’s withdrawn Wehrum Memo, makes proximity the controlling factor in oil and gas source determinations, and even adopts a similar quarter-mile benchmark.[50] In fact, the approach set out in the PADEP guidance is very similar to the Sixth Circuit’s reasoning in Summit Petroleum, including its rejection of functional interrelatedness and interdependence as a practical consideration in determining adjacency and adopting the dictionary definitions of “adjacent” and “contiguous.”[51] As expected, EPA Region III provided negative comments on the guidance, going so far as to suggest that the guidance was without legal effect.[52] EPA’s comments on the PADEP Guidance track the agency’s briefing position in Summit Petroleum.[53] In general, state permitting authorities have resisted an aggressive approach to aggregation, and the Sixth Circuit’s holding, at a minimum, bolsters that position with respect to oil and gas activities occurring over wide areas.

Conclusion

The Sixth Circuit’s Summit decision is certainly not the closing shot in the battle over aggregation in the oil and gas industry. In fact, EPA recently issued a memorandum expressly stating that “EPA does not intend to change its longstanding practice of considering interrelatedness in the EPA permitting actions in other jurisdictions [i.e., beyond the Sixth Circuit].”[54] But the Summit decision provides clear reasoning for states as they develop their own regulations and guidance for the industry. As in Pennsylvania, the decision furnishes legal support to state permitting authorities otherwise faced with an aggressive EPA policy stance on aggregation.[55] However, until we gain more clarity through EPA guidance, state determinations and court decisions, functional relatedness will still need to be evaluated for its potential implications on project development. A case-by-case approach is still necessary even where physical proximity is required.

 

 


Preferred Citation: William Bumpers & Paulina Williams, Sixth Circuit Pushes Back on EPA Oil and Gas Source Aggregation Under the Clean Air Act, 3 Harv. Bus. L. Rev. Online 41 (2013), https://journals.law.harvard.edu/hblr//?p=2690.

† William Bumpers is a partner in Baker Botts L.L.P’s Washington D.C. office, and Paulina Williams is an associate in the Austin office. The opinions expressed are those of the authors and do not necessarily reflect the views of the firm or its clients.

[1] 690 F.3d 733 (6th Cir. 2012).

[2] Memorandum from Stephen D. Page, Dir., Office of Air Quality Planning and Standards, U.S. Envtl. Prot. Agency, to Regional Air Div. Dirs., Regions I-X, Applicability of the Summit Decision to EPA Title V and NSR Source Determination (Dec. 21, 2012), http://www.epa.gov/nsr/documents/SummitDecision.pdf.

[3] Major sources are those that have the potential to emit 100 tons per year (tpy) or 250 tpy of any air pollutant depending on the type of stationary source. See 42 U.S.C. § 7479(1) (2006). Major modifications are modifications at existing sources that cause a significant increase in net emissions of the same pollutants. See 40 C.F.R. § 51.165(a)(1)(v)(A) (2012).

[4] See EPA, Basic Information, U.S. Envtl. Prot. Agency, http://www.epa.gov/nsr/info.html (last updated July 22, 2011).

[5] A “nonattainment area” is a locality where air pollution levels persistently exceed National Ambient Air Quality Standards, or that contributes to ambient air quality in a nearby area that fails to meet standards. See 42 U.S.C. § 7407 (2006). Prevention of Significant Deterioration (PSD) permitting applies in attainment areas. See id. §§ 7470–7479. Nonattainment NSR occurs in nonattainment areas. See id. §§ 7501–7514.

[6] 42 U.S.C. § 7503(a)(1)(A) (2006).

[7] Under Title V, a major source is defined as any stationary facility or source of air pollutants that directly emits, or has the potential to emit, 100 tpy of any air pollutant. Id. § 7602(j).

[8] See id. §§ 7661–7670.

[9] See id. § 7661b.

[10] See e.g., 30 Tex. Admin. Code § 116.620 (2012) (Texas standard permit for certain oil and gas facilities); Ark. Dep’t of Envtl. Quality, General Air Permit for Minor Source Natural Gas Compressor Stations Permit No. 1868-AGP-000 (Dec. 14, 2010), available at http://www.adeq.state.ar.us/air/branch_permits/pdfs/1868-AGP-000.pdf (Arkansas standard permit); Pa. Dep’t of Envtl. Prot., General Plan Approval and/or General Operating Permit (BAQ-GPA/GP – 5) (Revised Mar. 17, 2011), available at http://www.dep.state.pa.us/dep/deputate/airwaste/aq/permits/gp/Final_GP-5_Amendments_Approved.pdf (Pennsylvania standard permit).

[11] Conversely, there are instances in which industrial sources might seek single source status in order to “net” emissions, which is another calculation related to triggering NSR permitting. See 40 C.F.R. § 52.21(b)(3) (2012) (definition of net emissions increase applies to decreases or increases of emissions at the same stationary source within a five year period).

[12] Id. § 51.165(a)(1)(i).

[13] Id. § 51.165(a)(1)(ii).

[14] Id. The definition of a major source for purposes of Title V permitting includes the same basic criteria. See id. § 70.2.

[15] 636 F.2d 323, 397 (D.C. Cir. 1979).

[16] See 45 Fed. Reg. 52,676, 52,695 (Aug. 7, 1980) (codified at 40 C.F.R. pts. 51, 52, and 124).

[17] Each source is classified according to its primary activity, which is in turn determined by its principal product. Id.

[18] See Letter from Richard R. Long, Dir., Air Program, EPA Region VIII, to Julie Wrend, Legal Adm’r, Air Pollution & Control Div., Colo. Dep’t of Pub. Health and Env’t (Nov. 12, 1998), http://www.epa.gov/region7/air/nsr/nsrmemos/coorstri.pdf. This letter explains that EPA has identified three methods of establishing common control for purposes of source aggregation under NSR and Title V permitting rules: (1) common ownership; (2) operations control; and (3) control relationship. Id. First, common control exists where the same parent corporation owns multiple sources, or a parent and a subsidiary of the parent own multiple sources. Id. Common control can be established in the absence of common ownership if an entity has the power to direct the management and policies of a second entity through contractual agreement or a voting interest. Id. Finally, common control may also exist in the absence of common ownership if there is a contract for service relationship or a “support/dependency relationship” between the two. Id.

[19] See Citizens for Pa.’s Future v. Ultra Res., Inc., No. 4:11-CV-1360, 2012 WL 4434465 (M.D. Pa. Sept. 24, 2012) (CAA citizen suit in federal court is directly targeting Ultra Resources for alleged violations of the Act associated with the company’s shale gas operations spanning 558 square miles); William J. Hughes v. West Virginia Dep’t of Envtl. Prot., Appeal No. 10-03-AQB, (WV Air Quality Board Aug. 6, 2011) (Board denied petition by private parties alleging failure to aggregate two compressor stations 3 miles apart); WildEarth Guardians v. EPA, No. 11-CV-00001-CMA-MEH, 2011 WL 4485964 (D. Colo. Sept. 27, 2011) (EPA denied two petitions by WildEarth Guardians requesting that EPA object to Title V permits issued by the Colorado Department of Public Health and Environment, alleging should have aggregated the permitted oil and gas facilities. Appeal to 10th Circuit was settled after EPA Region VIII agreed to undertake a pilot program to study source determinations in the oil and gas industry).

[20] See 45 Fed. Reg. at 52,695.

[21] Id.

[22] Id.

[23] See Letter from Richard R. Long, Dir., Air Program, EPA Region VIII, to Lynn Menlove, Manager, New Source Review Section, Utah Div. of Air Quality (May 21, 1998), http://www.epa.gov/region07/air/title5/t5memos/util-trl.pdf (describing Acme Steel Company, Anheuser-Busch, and Great Salt Lake Minerals Determinations).

[24] See id. (responding to a request for guidance in defining “adjacent” for Title V and NSR source aggregation purposes).

[25] See e.g., Petition for Objection to Issuance of Operating Permit for Kerr-McGee Frederick Compressor Station, United States v. Kerr-McGee Corp., 2007 WL 2687992 (Jan. 3, 2007) (Petition by Rocky Mountain Clean Air Action, now WildEarth Guardians, objecting to the issuance of an operating permit to Kerr-McGee, a subsidiary of Anadarko Petroleum Corporation).

[26] Memorandum from William L. Wehrum, Acting Assistant Adm’r, Office of Air and Radiation, EPA, to Regional Adm’rs I-X, Source Determinations for Oil and Gas Industries (Jan. 12, 2007), http://www.epa.gov/region7/air/nsr/nsrmemos/oilgas.pdf.

[27] Id.

[28] Id. at 4–5.

[29] See, e.g., Robin Bravender, EPA Tosses Bush-Era ‘Aggregation’ Policy for Oil and Gas Industry, N.Y. Times, Oct. 14, 2009, available at http://www.nytimes.com/gwire/2009/10/14/14greenwire-epa-tosses-bush-era-aggregation-policy-for-oil-70149.html (illustrating previous opposition to Wehrum Memo).

[30] Memorandum from Gina McCarthy, Assistant Adm’r, Office of Air and Radiation, EPA, to Regional Adm’rs Regions I-X, Withdrawal of Source Determinations for Oil and Gas Industries (Sept. 22, 2009), http://www.epa.gov/region07/air/title5/t5memos/oilgaswithdrawal.pdf.

[31] Id.

[32] Id.

[33] See id.

[34] See, e.g., Gary McCutchen, Gurinder (Gary) Saini, Colin Campbell, Source Determinations for Oil and Gas Industries: EPA’s Changing Policy and One State’s Recent Experience, 20 Air Pollution Consultant, no. 6, 2010, at 5.3 (voicing opposition to McCarthy Memo and describing its effects as throwing “state and local agencies back into a complex, case-by-case decision-making mode with little real guidance, a disservice to both air permitting agencies and the oil and gas industry”).

[35] Compare Clean Air Act Operating Permit Program; Petition for Objection to State Operating Permit for Anadarko Petroleum Corporation—Frederick Compressor Station, 76 Fed. Reg. 10,361-01 (Feb. 24, 2011) (denial of petition for objection) with Clean Air Act Operating Permit Program; Petition for Objection to State Operating Permit for Williams Four Corners, LLC, Sims Mesa CDP Compressor Station, 76 Fed. Reg. 52,946-01 (Aug. 24, 2011) (grant of petition for objection).

[36] See Citizens for Pa.’s Future v. Ultra Res., Inc., 2012 WL 4434465, at *1.

[37] 690 F.3d 733, 741 (6th Cir. 2012).

[38] Id. at 735.

[39] Id. at 739–40.

[40] Id. at 741–744.

[41] Id. at 743–744.

[42] Id. at 746–749.

[43] Id. at 751.

[44] Id. at 753–755 (Moore, J., dissenting).

[45] Id. at 757 (Moore, J., dissenting).

[46] Id. at 753, n.2 (Moore, J., dissenting).

[47] See EPA, Frequently Asked Questions, U.S. Envtl. Prot. Agency, http://www.epa.gov/region1/eco/permits/title5/faq.html (last updated Jan. 2, 2013).

[48] Dep’t of Envtl. Prot., Bureau of Air Quality, Doc. No. 270-0810-006, Guidance for Performing Single Stationary Source Determination for Oil and Gas Industries, (Oct. 12, 2011), available at http://www.elibrary.dep.state.pa.us/dsweb/Services/Document-90745 [hereinafter PADEP Guidance].

[49] Tom Corbett Wins Pa. Governor’s Race, Associated Press, Nov. 2, 2010, available at http://www.lehighvalleylive.com/elections/index.ssf/2010/11/abc_declares_pa_governors_race.html.

[50] See PADEP Guidance, supra note 48, at 6–7.

[51] See id. at 5.

[52] See Letter from Diana Esher, Dir., Air Prot. Div., EPA Region III, to Krishnan Ramamurthy, Bureau of Air Quality, Pa. Dep’t of Envtl. Prot. (Nov. 21, 2011), http://www.cleanair.org/sites/default/files/epa2011_2268a.pdf.

[53] See Enclosure, Letter from Diana Esher, Dir., Air Prot. Div., EPA Region III, to Krishnan Ramamurthy, Bureau of Air Quality, Pa. Dep’t of Envtl. Prot. 4-5 (Nov. 21, 2011) (on file with authors).

[54] Memorandum from Stephen D. Page, supra note 2.

[55] For example, EPA Region III displayed its aggressive support of the broader approach to aggregation reflected in the McCarthy Memo in a January 10, 2012 letter to the Virginia Department of Environmental Quality (VADEQ), advising VADEQ to aggregate a gas-to-energy co-generation facility and a landfill that were separated by two miles and connected by a pipeline. See Letter from Kathleen Cox, Assoc. Dir., Office of Permits & Air Toxics, Air Prot. Div., EPA Region III, to Troy D. Breathwaite, Air Permits Manager, VADEQ (Jan. 10, 2012), http://www.epa.gov/region7/air/nsr/nsrmemos/gpc2012.pdf.

Filed Under: Energy, Featured, Home, U.S. Business Law, Volume 3 Tagged With: Energy

December 3, 2012 By wpengine

Shale Gas Development: The Implications of the Shale Gas Revolution for the Natural Gas Industry

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Mark R. Haskell * and Levi McAllister †

In the last ten years, new extraction techniques including hydraulic fracturing promise to expand domestic natural gas production substantially.[1] Shale gas is currently estimated to account for approximately twenty-five percent of domestic natural gas production.[2]

Shale gas has the potential to create new producing regions,[3] but it requires the creation of new infrastructure or the redesign and redeployment of existing infrastructure to access markets.[4] Shale gas also carries with it the potential for the transformative disruption of existing supply and transportation networks.[5]

This article explores some of the implications of the “shale gas revolution.” As explained below, the development of hydraulic fracturing and the production of shale gas fields promise to change the domestic and global natural gas industry in several ways. Due to the increased access to domestic gas resources through shale gas production, the price that gas marketers can receive for the sale of dry natural gas has been declining, which has prompted many marketers to focus increased attention to marketing natural gas globally through natural gas exports. [6] Due to the geographic location of shale gas fields, the historical relationship between natural gas basis differentials is changing, and a need for the construction of new natural gas infrastructure (or the realignment of existing infrastructure) is becoming apparent.[7]

A.             Volatility in Natural Gas Prices

In 2009, as natural gas producers began to produce shale gas by applying hydraulic fracturing extraction techniques, natural gas prices rapidly declined.[8] According to the Energy Information Administration, natural gas prices in the first seven months of 2012 are 70.3% lower than the average annual wellhead price of 2008.[9]

Natural gas now appears to be plentiful and abundant.[10] Utilities, manufacturers and other end users are looking at record low prices.[11] Further, the petrochemicals industry has seen a revival, which is driven in large part by the record low gas prices resulting from the abundance of shale production.[12]

However, the downtrend in natural gas pricing has also been a cause for concern for production companies. Some production companies may have entered into leasing arrangements prior to 2009 when gas prices were at record highs.[13] With low gas prices, many shale gas developers are facing financial challenges, and production companies are finding it unprofitable to pursue shale gas production.[14] As Maynard Holt, co-president of Tudor Pickering Holt & Company reportedly said, “[w]e just killed more meat than we could drag back to the cave and eat.”[15] Declining prices can inhibit investment in infrastructure and cause the delay or deferral of drilling programs. Low prices have caused some industry participants to divert investment from shale formations producing dry natural gas into natural gas liquids.[16]

B.             Renewed Interest in Natural Gas Exports

Increased supplies of natural gas resources coupled with declining domestic natural gas prices has created a separate, but related, issue with respect to shale gas development: the possibility of exporting natural gas.[17] Prior to the shale gas revolution, the United States was historically an importer of natural gas.[18] However, that perspective could be changing.

Natural gas may be exported in liquid form if the necessary infrastructure is developed and the required regulatory approvals are obtained. The process of exporting natural gas first requires the gas to be cooled in order to become liquefied natural gas (LNG), which is then pumped into natural gas tankers that are used to ship the LNG overseas.[19] Currently, however, the United States only has one operational processing plant that is able to liquefy gas and load it into such tankers.[20] That facility, the Kenai LNG Plant, is located in Nikiski, Alaska and currently exports LNG to Asia.[21]

The decreased availability of nuclear power post-Fukushima has contributed to an international interest in LNG.[22] To tap into that market, industry participants must first obtain the necessary regulatory approvals required to develop the infrastructure and export natural gas.[23] Federal law requires that approval be obtained from the Department of Energy (DOE) prior to exporting natural gas.[24] The authorization necessary to export depends on the country to which the gas will be exported. For example, the DOE possesses no discretion to deny an export application if the natural gas is to be exported to a country with which the United States has a Free Trade Agreement (FTA).[25] In contrast, the DOE performs a broader review of an export application if the natural gas is to be exported to a country with which the United States does not have a FTA.[26]

About a dozen applications seeking authorization to export LNG to non-FTA countries are currently pending before the DOE.[27] Companies seeking export authorization have argued to DOE that exports would lead to more jobs in the United States, and the revenues would help reduce the trade deficit.[28] Despite such possible benefits, the DOE has stated that it will not make any further decision on whether or not to approve such applications until it conducts an analysis into the economic impact of LNG exports.[29] The DOE has been commissioned to examine that impact, and an initial report was anticipated to have been issued in March 2012.[30] The report continues to be delayed.[31]

C.            A Shift in Basis Relationships

The shale revolution affects not only the absolute level of natural gas prices but the relative locational value of natural gas in local markets. In other words, shale gas development disrupts historical basis relationships.

The term “basis differential” refers to the difference between daily natural gas spot prices at regional hubs compared to the Henry Hub.[32] A large sustained basis demonstrates an opportunity to profitably construct a pipeline. Such differentials can occur due to congestion and bottlenecks between markets, which could be attributed to insufficient supply in a particular market.

Because the majority of domestic natural gas supply originated in the Gulf Coast region, obtaining natural gas in the Northeastern United States, for example, required transporting gas to that region from the Gulf Coast.[33] The price for natural gas in the Northeast United States would often be higher than the price for that same gas in the Gulf Coast region, reflecting, among other things, the cost of transportation and related services.[34] In turn, the basis differential with respect to a Northeastern hub would differ from a differential with respect to a Gulf Coast hub.

The shale revolution changes these historical basis relationships. Significant shale gas resources are located in geographic locations that have not been accustomed to producing natural gas.[35] North Dakota, Michigan, New York, Pennsylvania, Ohio, and West Virginia all hold significant amounts of natural gas that could be extracted through hydraulic fracturing.[36]

Recall that a large sustained basis differential demonstrates an opportunity to profitably construct a pipeline. As basis differentials shift, geographic regions where bottlenecks and/or constraints exist will also shift. [37] As a result, it may no longer be as profitable for a developer to construct a pipeline in a particular location. Instead, new strategies must be considered in light of the changing relationship among differentials.

D.            Infrastructure Development

The production of natural gas resources from shale plays affects the development of natural gas infrastructure in the United States. These implications concern both the need for new infrastructure in certain regions as well as impact on existing infrastructure with respect to the recovery of its costs.

In order to efficiently utilize natural gas extracted from shale plays, the necessary infrastructure must exist. This includes sufficient pipeline capacity to transport the extracted gas to a processing facility, processing facilities to process that gas, and pipeline capacity to transport processed gas to the market.[38] In many plays, this infrastructure has not yet materialized.

For example, Ohio is currently struggling with how to address such challenges with respect to the gas available for extraction from the Utica shale play. [39] Since December 2009, over 320 drilling permits have been issued by the Ohio Department of Natural Resources.[40] However, only slightly more than 110 wells have been drilled and, of those, only fourteen are currently producing natural gas or oil.[41] A lack of processing plants and pipelines has been cited as one of the reasons that production is not rapidly increasing.[42]

The development of new infrastructure comes with its own set of challenges. Depending on the proposal, state and perhaps federal regulatory approvals are required from the applicable regulator.[43] Those approvals relate to, among other things, the siting of the proposed project, an inquiry into whether the public interest requires the proposed project and, whether environmental risks warrant rejection of the proposed project.[44] Collectively, obtaining all required approvals and constructing a project is a time-intensive process that can take several years before the requisite infrastructure becomes operational.

Aside from new infrastructure development, the shale gas revolution creates challenges for existing infrastructure owners and developers. Because natural gas supplies historically originated in the Gulf Coast region, natural gas was delivered to markets through interstate transportation pipelines.[45] Those pipelines, and the rates that they charge shippers of natural gas on their systems, are regulated by the Federal Energy Regulatory Commission (FERC).[46] The FERC employs a cost-of-service rate design approach whereby a natural gas pipeline is permitted to recover the cost of providing service plus a reasonable return on its investment.[47] As a result, the rates a natural gas shipper pays depend on the cost the pipeline incurs to provide transportation services. As shale gas production increases in geographic regions that historically received gas supplies by interstate transport, those regions will require that less gas be transported via interstate pipelines originating in the Gulf Coast. In turn, owners of existing interstate pipelines could have lower demand for long-haul capacity over time. Changes in usage patterns could in theory change existing pipeline rate structures and lead to the adoption of new rate zones or new rate designs. These changes will pose challenges for pipelines and customers alike and affect depreciation of existing facilities, and increase competition between pipeline primary service offerings and the secondary market for released capacity.

E.             Conclusion

Shale gas production has been heralded as a positive development by many.[48] The existence of previously unanticipated natural gas resources in areas that historically have not been hotbeds for natural gas production creates jobs for those regions and provide financial injections into local economies.[49] Similarly, increased natural gas supplies have resulted in lower natural gas prices for consumers of that gas.[50]

The long-term effective and efficient development of shale gas resources carries with it both opportunity and significant risk. Pipelines, pipeline customers, consumers, and marketers will be coping with the consequences of this fundamental shift in supply conditions over the coming years.

We are in midst of a significant transition of the domestic natural gas industry. Will natural gas development continue at current levels given depressed pricing conditions? Will regulators facilitate the development of a truly international market for natural gas by approving LNG export projects? How do changes in basis differentials interact with the need for infrastructure development? How will the costs of infrastructure idled by new sources of production be paid? Only when some of these questions are answered can we realistically assess the true impacts of the shale revolution.

 


Preferred Citation: Mark R. Haskell & Levi McAllister, Shale Gas Development: The Implications of the Shale Gas Revolution for the Natural Gas Industry, 3 Harv. Bus. L. Rev. Online 33 (2012), https://journals.law.harvard.edu/hblr//?p=2611.

* Mark R. Haskell is a Partner with the law firm of Morgan, Lewis & Bockius in Washington, DC. He is a 1982 graduate of the University of Maine and a 1985 graduate of Harvard Law School. His practice has focused primarily on regulatory compliance, enforcement, litigation, and dispute resolution affecting market participants in the natural gas, oil, petrochemical, and electric industries. The views expressed in this article are those of the authors alone and do not necessarily reflect those of the authors’ law firm or its clients. The authors and their firm represent, among other clients, natural gas producers and marketers, local distribution companies, end-users, and one developer of an LNG export terminal project.

† Levi McAllister is an Associate with the law firm of Morgan, Lewis & Bockius in Washington, DC. He is a 2003 graduate of the University of Texas at Austin and a 2008 graduate of American University’s Washington College of Law.

[1] Elisabeth Rosenthal, U.S. Is Forecast to Be No. 1 Oil Producer, N.Y. Times, Nov. 13, 2012, at B6, available at http://www.nytimes.com/2012/11/13/business/energy-environment/report-sees-us-as-top-oil-producer-in-5-years.html?ref=us.

[2] Deloitte Ctr. for Energy Solutions, Public Opinions on Shale Gas Development 1 (2012), available at http://www.deloitte.com/assets/Dcom-UnitedStates/Local%20Assets/Documents/Energy_us_er/us_er_ShaleSurveypaper_0412.PDF.

[3] See Deloitte MarketPoint LLC & Deloitte Ctr. for Energy Solutions, Made in America: The Economic Impact of LNG Exports from the United States 6 (2011), available at http://www.deloitte.com/assets/Dcom-UnitedStates/Local%20Assets/Documents/Energy_us_er/us_er_MadeinAmerica_LNGPaper_122011.pdf [hereinafter Deloitte, Made in America].

[4] See David L. Goldwyn, Making an Energy Boom Work for the U.S., N.Y. Times, Nov. 12, 2012, http://www.nytimes.com/2012/11/13/business/energy-environment/making-an-energy-boom-work-for-us.html?pagewanted=all.

[5] See Deloitte, Made in America, supra note 3.

[6] Daniel Gilbert & Tom Fowler, Natural Gas Glut Pushes Exports, Wall St. J., Oct. 5, 2012, at A1, available at http://online.wsj.com/article/SB10000872396390444223104578036403362012318.html.

[7] See Deloitte, Made in America, supra note 3.

[8] Matthew Philips, Is Natural Price Too Cheap to Drill?, Bloomberg Businessweek, Apr. 17, 2012, http://www.businessweek.com/articles/2012-04-17/is-natural-gas-too-cheap-to-drill.

[9] See Energy Info. Admin., U.S. Dep’t of Energy, Monthly Energy Review Nov. 2012 131 tbl. 9.10 (Nov. 2012), available at http://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf. Table 9.10 provides the annual average wellhead price of natural gas since 1973 through 2009. Id. Table 9.10 also provides the average wellhead price of natural gas for each month during 2010, 2011 and the first seven months of 2012. Id. In 2008, the average wellhead price of natural gas was $7.97. Id. In contrast, the average wellhead price of natural gas for the first seven months of 2012 was $2.37. Id.

[10] Gilbert & Fowler, supra note 6.

[11] Id.

[12] See Molly Ryan, Houston Sees Resurgence in Manufacturing Due to Petrochemical Rebirth, Hous. Bus. J., July 27, 2012, http://www.bizjournals.com/houston/print-edition/2012/07/27/petrochemical-rebirth.html?page=all.

[13] See Clifford Krauss & Eric Lipton, After the Boom in Natural Gas, N.Y. Times, Oct. 20, 2012, at BU1, available at http://www.nytimes.com/2012/10/21/business/energy-environment/in-a-natural-gas-glut-big-winners-and-losers.html?pagewanted=all.

[14] See id.

[15] Id.

[16] Valerie Wood, Natural Gas Price Picture May Change by Late 2012, Pipeline & Gas J., Sept. 2011, at 16.

[17] Gilbert & Fowler, supra note 6.

[18] Id.

[19] See, e.g., Rebecca Smith & Mari Iwata, Japanese Buyers Line Up for U.S. Shale Gas, Wall St. J., May 24, 2012, at B8, available at http://online.wsj.com/article/SB10001424052702303505504577406061245167558.html (describing export process, which requires cooling and liquefying gas before loading it onto tankers).

[20] Yereth Rosen, ConocoPhillips Restarts LNG Exports from Alaska, Reuters, June 14, 2012, available at http://www.reuters.com/article/2012/06/14/us-conoco-lng-idUSBRE85D06C20120614.

[21] Id.

[22] See Smith & Iwata, supra note 19.

[23] See id.

[24] 15 U.S.C. § 717b (2006).

[25] See U.S. Dep’t of Energy, Fossil Energy: How to Apply, Energy.gov, http://www.fossil.energy.gov/programs/gasregulation/How_to_Obtain_Authorization_to_Import_an.html (last updated Nov. 6, 2012).

[26] See id.

[27] Office of Oil & Gas Global Sec. & Supply, Office of Fossil Energy, U.S. Dep’t of Energy, Applications Received by DOE/FE to Export Domestically Produced LNG from the Lower-48 States (as of Nov. 29 2012), http://fossil.energy.gov/programs/gasregulation/reports/Long%20Term%20LNG%20Export%20Concise%20Summary%20Table%2011-29-12.nwood.pdf.

[28] See, e.g., LNG Development Company, LLC; Application for Long-Term Authorization To Export Liquefied Natural Gas Produced From Canadian and Domestic Natural Gas Resources to Non-Free Trade Agreement Countries for a 25-Year Period, 77 Fed. Reg. 55,197-02, 55,198 (Sept. 7, 2012) (describing creation of new construction jobs and projected reduction in trade deficit).

[29] See Susan L. Sakmar, Politics and US LNG Export Project Heat Up, Nat. Gas & Electricity J., Oct. 2012, at 1, available at http://www.naturalgaselectricitynews.com/sample-articles/politics-and-us-lng-export-projects-heat-up.aspx.

[30] U.S. Government Further Delays LNG Export Decision, ICIS Heren (Mar. 30, 2012, 10:51 AM), http://www.icis.com/heren/articles/2012/03/30/9546199/us-government-further-delays-lng-export-decision.html.

[31] Id.

[32] See, e.g., Deloitte, Made in America, supra note 3, at 15 (describing differential between Henry Hub and New York City prices).

[33] See id. at 6.

[34] Id. at 13.

[35] See, e.g., John A. Sullivan, Thanks to Bakken, North Dakota Could Surpass California Output, Nat. Gas. Wk., May 31, 2010, at 8, available at 2010 WLNR 12262297 (describing North Dakota’s rising production of Bakken shale gas).

[36] Id.See also Ben Casselman & Russell Gold, Cheap Natural Gas Gives Hope to Rust Belt, Wall St. J., Oct. 24, 2012, http://online.wsj.com/article/SB10000872396390444549204578020602281237088.html.

[37] See Deloitte Ctr. for Energy Solutions & Deloitte MarketPoint LLC, Navigating a Fractured Future Insights into the Future of the North American Natural Gas Market 14 (2011), available at http://www.usea.org/sites/default/files/event-file/511/Natural_Gas_Study_Presentation_for_USEA.pdf.

[38] See Liam Denning, Pipe Dreams in America’s New Energy Landscape, Wall St. J., July 30, 2011, http://online.wsj.com/article/SB10001424053111904800304576476154127256730.html.

[39] Jeff Bell, Ohio’s Shale Play Delayed by Infrastructure Needs, Columbus Bus. First, Aug. 10, 2012, http://www.bizjournals.com/columbus/print-edition/2012/08/10/infrastructure-needs-delay-drilling-in.html?page=all.

[40] Id.

[41] Id.

[42] Id.

[43] See, e.g., Regulations Implementing the Energy Policy Act of 2005: Coordinating the Processing of Federal Authorizations for Applications Under Sections 3 and 7 of the Natural Gas Act and Maintaining a Complete Consolidated Record, 71 Fed. Reg. 30632-01 (proposed May 30, 2006) (to be codified in 18 C.F.R. pt. 153, 157, 375, 385) (describing collaboration necessary to harmonize regulatory requirements in natural gas projects).

[44] See Jeremy Knee, Rational Electricity Regulation: Environmental Impacts and the “Public Interest,” 113 W. Va. L. Rev. 739, 758 (2011).

[45] See Deloitte, Made in America, supra note 3, at 6, 13.

[46] Fed. Energy Regulatory Comm’n, What FERC Does, http://www.ferc.gov/about/ferc-does.asp (last visited Nov. 13, 2012).

[47] See Knee, supra note 44, at 747.

[48] See, e.g., Jim Efstathiou Jr., Fracking Will Support 1.7 Million Jobs, Study Shows, Bloomberg Businessweek, Oct. 23, 2012, http://www.businessweek.com/news/2012-10-23/fracking-will-support-1-dot-7-million-jobs-study-shows (describing President Obama’s support of hydraulic fracturing to increase jobs in the United States).

[49] Id.

[50] Gilbert & Fowler, supra note 6.

Filed Under: Energy, Featured, Home, U.S. Business Law, Volume 3 Tagged With: Energy, Shale Gas

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