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New Margin Requirements for Uncleared Swaps

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Craig Stein & Paul N. Watterson, Jr.*

One of the fundamental changes that the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”)[1] made in the financial markets has been to force most over-the-counter swap transactions onto exchanges and impose regulations on transactions that remain uncleared by a central counterparty.  At the same time, laws and regulations adopted by the European Commission and other nations have imposed similar, but by no means identical, requirements on swap markets outside the United States.  This article reviews one aspect of these changes in the over-the-counter swap markets:  the new margin requirements for uncleared swaps.  Because margin for uncleared swaps has to date been set by each dealer in negotiations with individual customers, the transition to margin requirements imposed by regulators is likely to be difficult.  There have also been predictions that the discrepancies between the margin requirements proposed by U.S. regulators and those proposed by regulators outside the U.S. will result in fragmentation of the uncleared swap markets.

I.          Background

The Dodd-Frank Act, enacted on July 21, 2010,[2] requires swap dealers, major swap participants, security-based swap dealers and major security-based swap participants (each, a “swap entity” and, collectively, “swap entities”) to register with the Commodity Futures Trading Commission (“CFTC”) or the Securities and Exchange Commission (“SEC”).[3]  The Dodd-Frank Act also requires the Office of the Comptroller of the Currency Treasury (“OCC”), the Board of Governors of the Federal Reserve System (“Board”), the Federal Deposit Insurance Corporation (“FDIC”), the Farm Credit Administration (“FCA”) and the Federal Housing Finance Agency (“FHFA”) (collectively, “the Prudential Regulators”) to adopt joint rules for swap entities under their respective jurisdictions imposing initial and variation margin requirements on all swaps not cleared by a central counterparty (“CCP”).[4]  The Dodd-Frank Act also requires the CFTC and the SEC separately to adopt rules imposing margin requirements for swap entities for which there is no Prudential Regulator.[5]

In April 2011, the CFTC proposed rules to implement the foregoing provisions of the Dodd-Frank Act,[6] and two weeks later the Prudential Regulators proposed substantially similar rules.[7] The SEC is not expected to propose similar rules for security-based swaps until next year.  Before these rules became effective, in July 2012, the Basel Committee on Banking Supervision (“BCBS”) and the board of the International Organization of Securities Commissions (“IOSCO”) proposed an international framework for margin requirements on uncleared swaps with the goal of creating an international standard for uncleared swaps.[8]  This international framework, finalized in September 2013[9], articulates eight key principles for uncleared swaps margin rules:[10]

  1. Appropriate margining practices should be in place with respect to all uncleared derivative transactions;
  2. Financial firms and systemically important non-financial entities (covered entities) that engage in non-centrally cleared derivatives must exchange initial and variation margins;
  3. The methodologies for calculating initial and variation margins should be consistent across covered entities and ensure that all counterparty risk exposures are covered with a high degree of confidence;
  4. To ensure that collateral will generate proceeds sufficient to protect against losses in the event of a counterparty default, collateral should be highly liquid and should, after accounting for an appropriate haircut, be able to hold its value in a time of financial stress;
  5. Initial margin should be exchanged on a gross basis and held in such a way as to ensure that: (a) the margin collected is immediately available to the collecting party in the event of the counterparty’s default; and (b) the collected margin is subject to arrangements that fully protect the posting party;
  6. Requirements for transactions between affiliates are left to the national supervisors;
  7. Requirements for margining uncleared swaps should be consistent and not duplicative across jurisdictions; and
  8. Margin requirements should be phased in over an appropriate period of time.

In September and October 2014, the CFTC[11] and the Prudential Regulators[12] re-proposed rules for margin requirements for uncleared swaps (the “CFTC Proposal” and the “PR Proposal,” respectively).  In reproposing the rules, the regulators clearly took into account the BCBS/IOSCO framework, but nonetheless there are important discrepancies between the proposed rules and the framework.

II.         Scope of Coverage

The BCBS/IOSCO framework applies to all uncleared OTC derivatives.[13]  The PR Proposal imposes initial and variation margin requirements on prudentially regulated swap entities such as registered swap dealers that are U.S. or foreign banks (“PR Covered Swap Entities”) entering into uncleared swaps and security-based swaps with the types of counterparties discussed below.[14] PR Covered Swap Entities would be required to post and collect initial and variation margin when facing these counterparties even if the counterparties themselves are not subject to regulation under the Dodd-Frank Act.[15]  The Prudential Regulators are proposing to adopt what they refer to as a risk-based approach.[16]

The CFTC Proposal imposes initial and variation margin requirements on swap dealers and major swap participants that are not regulated by a Prudential Regulator, such as registered swap dealers that are not U.S. or foreign banks (“CFTC Covered Swap Entities”).[17]  The CFTC Proposal generally applies only to uncleared swaps.  However, deliverable foreign exchange forwards and foreign exchange swaps are not considered swaps under the Commodity Exchange Act as amended by the Dodd-Frank Act for purposes of uncleared swap margin requirements, as determined by the U.S. Department of Treasury in 2012.[18] As a result, PR Covered Swap Entities may be required to pay variation margin for foreign exchange forwards and foreign exchange swaps while CFTC Covered Swap Entities will not be required to pay it.[19]

III.        Counterparties

Both the PR Proposal and the CFTC Proposal distinguish among four different types of swap counterparties:

  1. Counterparties that are themselves PR Covered Swap Entities;
  2. Counterparties that are financial end users with a material swaps exposure;
  3. Counterparties that are financial end users without a material swaps exposure; and
  4. All other counterparties.[20]

The PR Proposal provides a list of entities that would qualify as financial end users[21] as well as a list of entities excluded from that definition.[22]  It is not consistent with the definition of a “financial entity” in Section 2(h) of the Commodity Exchange Act[23], which on its own is likely to cause confusion in the markets. In addition, the enactment of the Business Risk Mitigation and Price Stabilization Act of 2015 (the “RMPS Act”) on January 13, 2015 appears to have heightened the significance of such confusion.  By way of background, the RMPS Act amends sections 731 and 764 of the Dodd-Frank Act to provide that rules with respect to initial and variation margin requirements adopted by the CFTC, the SEC and the Prudential Regulators will not be applicable to entities that qualify for the end-user exception to the mandatory clearing requirement set forth in section 2(h)(7)(A) of the Commodity Exchange Act and corresponding section 3C(g)(1) of the Securities Exchange Act.  This statutory exemption  is available to any entity that: (i) is not a financial entity; (ii) uses swaps to hedge or mitigate commercial risk; and (iii) notifies the CFTC regarding the manner in which it generally meets its financial obligations in respect of uncleared swaps.  The “is not a financial entity” condition is with reference to the definition of “financial entity” set forth in section 2(h)(7)(C) of the CEA.  However, in an attempt to avoid difficulties experienced in determining which market participants should qualify as “financial entities” pursuant to the statutory language, the CFTC and the Prudential Regulators sought in the PR Proposal and the CFTC Proposal to provide clarity about whether particular entities would be subject to the margin rules by including in the reproposed rules the alternative concept of “financial end user.”  But at the time of this writing, considering that the RMPS Act specifically refers to “financial entity” instead of “financial end user”, it is unclear whether the CFTC and the Prudential Regulators will continue to rely in the final rules on the current definition of “financial end user” or will instead conform to the statutory definition of “financial entity”.

Under the PR Proposal, financial end users include banks; credit unions; broker-dealers, investment advisers, CPOs, CTAs or FCMs; investment funds, including a private fund under Section 202(a) of the Investment Advisers Act; investment vehicles operating in reliance on Section 3(c)(5)(C) or Rule 3a-7 of the 1940 Act; and insurance companies.[24]  “Financial end user” is defined in the CFTC Proposal in substantially the same way as in the PR Proposal[25], but there are slight differences.

In the PR Proposal and the CFTC Proposal, “material swaps exposure” is defined to mean that a counterparty has a consolidated average daily aggregate notional amount of uncleared swaps, uncleared security-based swaps, foreign exchange forwards and foreign exchange swaps with all other counterparties for June through August of the previous year that exceeds $3 billion.[26]

The definition of financial end users is so broad that it will require exceptions to be made, either in the final rules or in no-action letters, in order to avoid unintended disruptions of markets.  For example, it includes securitization vehicles[27], and these entities do not currently post margin on uncleared swaps and in most cases are prohibited by their transaction documents and rating agency criteria from doing so.  Structured finance transactions where the swap counterparty is either secured by a senior claim on pledged collateral held by a special purpose vehicle or is otherwise entitled to a senior priority claim on the assets of the special purpose vehicle do not pose systemic risk to the broader market.  Such credit support arrangements protect swap counterparties without the use of initial margin or variation margin as required under the proposed rules.

IV.         Margin Requirements by Counterparty

PR Covered Swap Entities must collect and post a minimum amount of initial margin when entering into an uncleared swap with any other PR Covered Swap Entity and with any financial end user that has a material swaps exposure.[28]  Variation margin requirements would apply to swap transactions where a PR Covered Swap Entity enters into a trade with another PR Covered Swap Entity or a financial end user (regardless of whether the financial end user has a material swaps exposure).[29]  A PR Covered Swap Entity may make its own credit judgment about whether to collect initial margin or variation margin from other types of counterparties based on the credit risk posed by the counterparty and the risks of such swaps or security-based swaps.[30]

The CFTC Proposal requires CFTC Covered Swap Entities to post and collect initial margin for uncleared swaps from any counterparty that is a CFTC Covered Swap Entity or financial end user with material swaps exposure.[31]  A CFTC Covered Swap Entity must post and collect variation margin in transactions with another CFTC Covered Swap Entity or a financial end user (regardless of whether the counterparty has material swaps exposure).[32]  There is no requirement for CFTC Covered Swap Entities to exchange margin with non-financial end users.  However, CFTC Covered Swap Entities are permitted to agree to initial and variation margin requirements and thresholds with such non-financial end users.

This aspect of the proposed rules represents a departure from the BCBS/IOSCO framework, under which initial margin is not required to be posted or collected by entities with an average daily aggregate notional amount of uncleared swaps below approximately $11 billion.[33]

V.          Initial Margin Calculation Methodology

For initial margin, the PR Proposal would require a PR Covered Swap Entity to calculate its minimum initial margin requirement in one of two ways.  It may use a standardized margin schedule set forth in the PR Proposal, or it may use an internal margin model that satisfies criteria set forth in the PR Proposal and has been approved by the Prudential Regulator.[34]  Like the PR Proposal, the CFTC Proposal permits CFTC Covered Swap Entities to calculate initial margin by using either a risk-based model or a standardized table method.[35]

In their comment letters, many swap market participants argued that each covered swap entity should be permitted to use its proprietary initial margin model, rather than being required by the proposed rules to use a model from a vendor or clearing organization or a model that has been approved by the Prudential Regulators.[36]

VI.         Calculating Variation Margin

Unlike the PR Proposal, the CFTC Proposal requires control mechanisms for the calculation of variation margin.[37]  A CFTC Covered Swap Entity must create and maintain documentation setting forth its calculation methodology to allow the counterparty, the CFTC and any Prudential Regulator to calculate a reasonable approximation of the margin requirement independently.[38]  It is also required to evaluate the reliability of its data sources at least annually and make adjustments, as appropriate.[39]  In addition, the CFTC Proposal requires a CFTC Covered Swap Entity to have in place alternative methods for determining the value of an uncleared swap in the event of the unavailability of any input required to value a swap, and the CFTC may at any time require a CFTC Covered Swap Entity to provide further data or analysis concerning the methodology or data source used to value a swap for variation margin purposes.[40]

VII.        Thresholds

Under the PR Proposal, initial margin must be posted and collected on a daily basis (with the collection and posting of initial margin beginning no later than the business day following the day of entry into the swap) in response to changes in portfolio composition or other factors that would change the required initial margin amounts.[41]  PR Covered Swap Entities are permitted to adopt a maximum initial margin threshold of $65 million, below which they need not collect or post initial margin from or to other PR Covered Swap Entities or financial end users with material swaps exposure.[42]  The threshold would be applied on a consolidated basis and would apply both to the consolidated PR Covered Swap Entity as well as to the consolidated counterparty.[43]  With respect to variation margin, no threshold amounts would be permitted; but a minimum transfer amount of $650,000 is permitted (the minimum transfer amount applies to all margin posted, initial and variation margin combined).[44]  Variation margin also would be required to be posted and collected on a daily basis.[45]

The CFTC Proposal, like the PR Proposal, permits a CFTC Covered Swap Entity to reduce the amount of initial margin by a threshold amount that is established by the CFTC Covered Swap Entity but that may be no greater than $65 million.[46]  The initial margin threshold amount must be applied on a consolidated basis.  Initial margin must be posted and collected on a daily basis commencing on or before the business day after execution of an uncleared swap.[47]

Swap market participants have objected to these standardized thresholds, arguing that instead the rules should permit each covered swap entity to determine the relevant thresholds for its counterparties, subject to regulatory review.[48]

VIII.       Eligible Collateral

Although the BCBS/IOSCO framework does not distinguish between forms of initial and variation margin collateral[49], the proposed rules permit a wide variety of securities to be delivered as initial margin while restricting variation margin to cash.  Under the PR Proposal, eligible collateral is limited to high-quality assets that are expected to remain liquid and retain their value, after accounting for an appropriate risk-based haircut.  Eligible collateral for variation margin is limited to cash in U.S. dollars or the currency in which payment obligations under the swap are required to be settled.[50]  Eligible collateral for initial margin includes cash, U.S. treasuries and agencies, certain foreign government debt securities, certain corporate debt securities, certain listed equities or gold.[51]  The value of any eligible collateral that is collected and held to satisfy initial margin requirements is subject to the haircuts described in the PR Proposal.[52]  A PR Covered Swap Entity is required to monitor the market value and eligibility of all collateral to satisfy the initial margin requirements.[53]  To the extent that the market value of such collateral has declined or if it is no longer eligible collateral, the PR Covered Swap Entity must promptly collect additional eligible collateral.[54]

The list of eligible collateral (including haircuts) in the CFTC Proposal is substantially the same as in the PR Proposal.[55]  CFTC Covered Swap Entities also are required to monitor the market value and eligibility of all collateral collected to satisfy initial margin requirements.

This is another aspect of the proposed rules where swap market participants have commented that the rules should permit covered swap entities to determine eligible collateral and relevant haircuts for such collateral, subject to regulatory review.[56]

IX.         Custodial Agreements and Segregation

Under the PR Proposal, initial margin must be segregated at custodians that are not affiliates of the PR Covered Swap Entity or the counterparty.[57] On the other hand, variation margin is not required to be segregated at an independent third-party custodian.[58]  The segregation requirement applies only to the minimum amount of initial margin that a PR Covered Swap Entity is required to collect from a swap entity or a financial end user with material swaps exposure; however, it applies to all collateral (other than variation margin) that the PR Covered Swap Entity posts to any counterparty.[59]  The custodial agreement must prohibit rehypothecating, repledging, reusing or otherwise transferring any of the funds the third-party custodian holds.[60]  Substitution of collateral and reinvestment of posted collateral is permitted.[61]  Unlike initial margin, variation margin may be rehypothecated by the recipient.[62]

Similar to the PR Proposal, the CFTC Proposal requires any initial margin posted by a CFTC Covered Swap Entity, and the initial margin that is required to be collected by a CFTC Covered Swap Entity, to be held by an independent third-party custodian.[63]  The CFTC Proposal, like the PR Proposal, requires the custodian agreement to limit rehypothecation and to permit substitution and reinvestment of collateral.

Under the BCBS/IOSCO framework, the customer has the option to segregate initial margin[64] and the customer may consent to rehypothecation.[65]  The PR Proposal and the CFTC Proposal are therefore more restrictive than the BCBS/IOSCO framework since under the PR Proposal and the CFTC Proposal segregation is required and rehypothecation is prohibited.

In comment letters swap market participants have expressed a desire to continue the current practice, which these segregation requirements would ban, of allowing parties to agree that the custodian for their margin will be an affiliate of either counterparty.[66]

X.          Interaffiliate Swaps

The PR Proposal and the CFTC Proposal do not provide an exemption from these margin requirements for uncleared swap transactions between affiliates.  The BCBS/IOSCO framework left the decision to national supervisors[67], so if national supervisors outside the United States provide an exemption, it could place U.S. entities at a competitive disadvantage.

The exemption of inter-affiliate swaps is an issue that swap market participants, particularly global financial entities that have historically used back-to-back swaps to consolidate and manage market risk exposures centrally at a single affiliate, have consistently (and almost universally) requested.[68]  The generally expressed rationale for such an exemption is that inter-affiliate swaps do not increase systemic risk because losses on a trade that accrue to one affiliate are equally offset by gains to the affiliate on the other side of the trade, resulting in a net wash for the consolidated entities.  So posting of collateral for inter-affiliate swaps is not necessary to control systemic risk.

XI.         Netting and Treatment of Legacy Trades

Under the PR Proposal and the CFTC Proposal, the margin amounts posted and received for transactions made under an eligible master netting agreement could be fully netted.  While the margin requirements would not be applicable to trades entered into prior to the effective date of the new rules, if such “legacy” trades were made under the same master netting agreement as new trades made after the effective date, such legacy trades would be required to satisfy the new margin requirements.[69]

The proposal by the U.S. regulators to condition grandfathering of legacy trades on the documentation of those swaps under separate eligible master netting agreements from new swaps, would increase credit risk and systemic risk by reducing the netting of trades.[70]  Cross-product portfolio margining arrangements across cleared and uncleared swaps and other non-derivative products remain a critical issue for market participants.[71]

XII.        Trading Documentation

The PR Proposal requires the trading agreements between a PR Covered Swap Entity and a counterparty that is either another PR Covered Swap Entity or a financial end user to include credit support provisions that meet the requirements of the rule.[72]  Such credit support arrangements must specify the methods, procedures, rules and inputs for determining the value of each swap and contain dispute resolution procedures.[73]  In contrast, the CFTC Proposal requires CFTC Covered Swap Entities to enter into trading agreements that contain such credit support provisions with all uncleared swap counterparties, including non-financial end users.[74]

CFTC rules and regulations already require swap trading documentation to include methods, procedures, rules and inputs for swap valuation and a valuation dispute resolution process and disclosure of the methodology and assumptions used to prepare the daily mark.[75]  The proposed rules are duplicative and impose additional documentation requirements related to valuation that are unnecessary and will be burdensome for swap market participants.

XIII.       Effective Dates

If the proposed rules are implemented, as currently drafted, PR Covered Swap Entities and CFTC Covered Swap Entities will need to comply with the margin requirements for swaps entered into on or after December 1, 2015 with respect to variation margin.[76] For initial margin the compliance date is December 1, 2015 if both the PR Covered Swap Entity (and its affiliates) or the CFTC Covered Swap Entity (and its affiliates), as applicable, and the counterparty (and its affiliates) have an average daily aggregate notional amount of uncleared swaps, uncleared security-based swaps, foreign exchange forwards and foreign exchange swaps for June through August 2015 that exceeds $4 trillion.[77]  However, if a party has a lower volume of uncleared swap and foreign exchange trading, the effective date is deferred to December 1, 2016, if for June through August 2016 such volume exceeds $3 trillion; December 1, 2017, if for June through August 2017 it exceeds $2 trillion; and December 1, 2018, if for June through August 2018 it exceeds $1 trillion.[78]  The new requirements will become effective for all counterparties on December 1, 2019.[79]

It is unlikely that the final rules will be finalized before mid-2015.  As a result, market participants will have very little time before the December 1, 2015 deadline to put the necessary legal, operational, risk management and technology in place to implement these new regulations.  A deferral of the proposed effective dates is needed to provide additional time after the finalization of the rules is necessary to ensure a smooth and efficient implementation of the rules.

However, on March 18, 2015 the BCBS and IOSCO jointly announced that the implementation schedule set forth in the international framework was being extended by nine months.  In addition, the requirement to exchange variation margin was made subject to a six month phase-in period.[80]  The U.S. regulators have not yet officially followed suit, but CFTC Commissioner Timothy Massad has been quoted as stating that the CFTC is also considering pushing back its implementation timeline by a matter of months.[81]

XIV.        Extraterritoriality

The PR Proposal excludes any foreign non-cleared swap or foreign non-cleared security-based swap of a foreign covered swap entity.[82]  A “foreign non-cleared swap” is an uncleared swap of a foreign covered swap entity where neither the counterparty nor any guarantor of either party is:  (1) organized under the laws of the United States or any state (including a U.S. branch, agency or subsidiary of a foreign bank); (2) a branch or office of an entity organized under the laws of the United States or any state; or (3) a PR Covered Swap Entity controlled by an entity organized under the laws of the United States or any state.[83] A “foreign covered swap entity” is a PR Covered Swap Entity that is not:  (1) organized under the laws of the United States or any state (including a U.S. branch, agency or subsidiary of a foreign bank); (2) a branch or office of an entity organized under the laws of the United States or any state; or (3) a PR Covered Swap Entity controlled by an entity organized under the laws of the United States or any state.[84]  In addition to the foregoing exclusion, the PR Proposal would permit “substituted compliance”:  Foreign covered swap entities could meet the requirements of the rule by complying with the requirements of a non-U.S. regulator in the event that a comparability determination is made by the Prudential Regulators, provided that the covered swap entity’s obligations under the swap are not guaranteed by a U.S. entity.[85]

Unlike the PR Proposal, the CFTC Proposal does not include exemptions to its margin requirements for transactions outside the United States markets.  The CFTC Proposal includes an advance notice of proposed rulemaking and asks for public comment on alternative approaches including:  (1) application of the rules according to the PR Proposal; or (2) application of the uncleared swap margin CFTC rules according to the “transaction-level requirements” of the CFTC’s earlier cross-border guidance or the “entity-level requirements.”[86]

One issue on which all swap market participants agree is “harmonization”:  margin rules should be consistent across different jurisdictions and within the United States or, at a minimum, require a transaction to comply with only one jurisdiction’s rules where such harmony is lacking.[87]  In the U.S., the SEC has yet to re-propose its rules on margin.  And with respect to the CFTC Proposal, there has been no determination to permit substituted compliance for non-U.S. margin rules that are consistent with the BCBS/IOSCO framework.  Substituted compliance is necessary to avoid having margin rules from two different jurisdictions with inconsistent requirements applying simultaneously to the same collateral transfer.

Swap market participants have argued that swaps between non-U.S. covered swap entities and non-U.S. counterparties should not be subject to the U.S. margin rules, even if such entities are affiliated with U.S. companies.[88]  The definition of what is a “non-U.S.” entity is also crucial:  non-U.S. covered swap entities should include non-U.S. branches, offices, subsidiaries and other non-U.S. affiliates of U.S. entities, and non-U.S. counterparties should include non-U.S. funds or other entities with a U.S. advisor and non-U.S. entities guaranteed by a U.S. entity.

XV.         Impact of Re-Proposed Margin Rules

Margin requirements today are established through bilateral negotiations between a dealer and its counterparty, and two-way margining is not current market practice for many participants in the swap market.  As a result, market participants will be required to make changes in longstanding business practices as well as significant investments to improve their collateral infrastructure. Collateral account control agreements with third-party custodians will need to be negotiated. Systems will need to be updated to support the new margin calculations, and reporting capabilities will need to be enhanced to track collateral.

Mandatory margin requirements are expected to lead to higher costs and reduced liquidity for uncleared swaps.  Since initial margin will not be permitted to be rehypothecated, industry participants will need a consistent supply of eligible collateral, which may result in a shortage of, and possibly a squeeze on, eligible collateral.  Counterparties may be increasingly reliant on transformation services if this shortage of eligible assets develops; dealers providing transformation services will lend eligible collateral to counterparties for a fee.

In addition, risk may also increase as the cost of customizing risk management tools will increase, causing counterparties to use more standardized swaps, which are less tailored to reduce the specific risks to which counterparties are exposed.  Risk will concentrate at central counterparty clearing houses as trades move away from the more expensive uncleared swaps market.  Such concentration at the central counterparties may have adverse consequences if risk management is not improved at central counterparties.  If the margin requirements for uncleared swaps become too costly, the markets for uncleared swaps may become disrupted and no longer viable, thereby adversely affecting the ability of market participants to manage risk effectively.

XVI.        Conclusion

ISDA estimates that as much as $1 trillion of new collateral may need to be posted if the rules for margin for uncleared swaps proposed by the CFTC and Prudential Regulators are adopted.[89]  This increased collateral demand would have a significant impact on financial markets.  While most swap market participants generally support measures to reduce risk in the swaps markets and incentivize clearing of swaps, many have expressed concerns that the proposed rules will have unintended consequences that will increase systemic risk and disrupt these markets.  The rules need to appropriately address the particular risks posed by uncleared swap transactions.  As currently proposed, the margin rules for uncleared swaps may be too costly and punitive.  If the market for uncleared swaps loses its viability, market participants will not be able to manage risk effectively.  Market participants need a well-functioning market for uncleared swaps in order to meet their trading and risk management needs, which often require the customized transactions which exchanges cannot by their nature offer.

 

Preferred citation: Craig Stein & Paul N. Watterson, Jr., New Margin Requirements for Uncleared Swaps, 5 Harv. Bus. L. Rev. Online 114 (2015), https://www.hblr.org//?p=4029.

* Craig Stein is a partner and co-head of the Structured Finance & Derivatives Group at Schulte Roth & Zabel LLP.  His practice focuses on swaps and other derivative products, including credit- and fund-linked derivatives, prime brokerage and customer trading agreements, and structured finance and asset-backed transactions.  Paul N. Watterson, Jr. is a partner and co-head of the Structured Finance & Derivatives Group at Schulte Roth & Zabel LLP.  He concentrates his practice on structured product and derivative transactions, the formation and representation of credit funds, and capital markets regulation.

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

[2] Id.

[3] See 7 U.S.C. § 6s(a) (2012); 15 U.S.C. § 78o-10(a).

[4] See 7 U.S.C. § 6s(e)(2)(A)(ii); 15 U.S.C. § 78o-10(e)(2)(A)(ii).

[5] See 7 U.S.C. § 6s(e)(2)(B)(ii); 15 U.S.C. § 78o-10(e)(2)(B)(ii).

[6] Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 76 Fed. Reg. 23,732 (Apr. 28, 2011).

[7] Margin and Capital Requirements for Covered Swap Entities, 76 Fed. Reg. 27,564 (May 11, 2011).

[8] See Basel Committee on Banking Supervision & Board of the International Organization of Securities Commissions, Consultative Document: Margin requirements for non-centrally-cleared derivatives (2012).

[9] See Basel Committee on Banking Supervision & Board of the International Organization of Securities Commissions, Margin requirements for non-centrally cleared derivatives (2014).

[10] See id. at 5.

[11] Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. 59,898 (Oct. 3, 2014).

[12] Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. 57,348 (Sept. 24, 2014).

[13] Except, the Framework does not apply for physically settled foreign exchange forwards and swaps. See Basel Committee on Banking Supervision & Board of the International Organization of Securities Commissions, Margin requirements for non-centrally cleared derivatives 7 (2014).

[14] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. 57,350.

[15] See id. at 57,354.

[16] See id.

[17] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. 59,902.

[18] Determination of Foreign Exchange Swaps and Foreign Exchange Forwards Under the Commodity Exchange Act, 77 Fed. Reg. 69,694 (Nov. 20, 2012).

[19] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. 57,351.

[20] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,398; Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,926.

[21] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,360.

[22] See id. at 57,362.

[23] See 7 U.S.C. § 2(h)(7)(C)(i).

[24] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,390.

[25] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,926.

[26] See id. at 59,927 & Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,391.

[27] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,903 & Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,361.

[28] See Margin and Capital Requirements for Covered Swap Entities,79 Fed. Reg. at 57,391.

[29] See id. at 57,392.

[30] See id. at 57,391,  57,392.

[31] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. 59,928.

[32] See id.

[33] See Basel Committee on Banking Supervision & Board of the International Organization of Securities Commissions, Margin requirements for non-centrally cleared derivatives 10 (March 2014).

[34] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,393.

[35] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,929.

[36] See e.g. ISDA / SIFMA Joint Comment Letter addressed to the CFTC (September 14, 2012); SIFMA Comment Letter addressed to Prudential Regulators (March 12, 2014).

[37] See 79 Fed. Reg. at 59,931.

[38] Id.

[39] Id.

[40] Id.

[41] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,391.

[42] See id. at 57,390.

[43] See id. at 57,366.

[44] See id. at 57,392.

[45] See id.

[46] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,927 (defining initial margin threshold amount).

[47] See id. at 59,928.

[48] See e.g. ISDA / SIFMA Joint Comment Letter addressed to the CFTC (July 11, 2011); ISDA / SIFMA Joint Comment Letter addressed to the CFTC (September 14, 2012); SIFMA Asset Management Group Comment Letter addressed to the CFTC (September 28, 2012).

[49] See Basel Committee on Banking Supervision & Board of the International Organization of Securities Commissions, Margin requirements for non-centrally cleared derivatives 17 (March 2014).

[50] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,392.

[51] See id.

[52] See id.

[53] See id.

[54] See id.

[55] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,931.

[56] See e.g. ISDA / SIFMA Joint Comment Letter addressed to the CFTC (September 14, 2012); ISDA Comment Letter addressed to the Prudential Regulators (November 26, 2012).

[57] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,393.

[58] Seeid. at 57,356.

[59] See id. at 57,393.

[60] See id.

[61] See id.

[62] See id.

[63] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,932.

[64] See Basel Committee on Banking Supervision & Board of the International Organization of Securities Commissions, Margin requirements for non-centrally cleared derivatives 20 (March 2014).

[65] See id. at 21.

[66] See e.g. ISDA / SIFMA Joint Comment Letter addressed to the CFTC (September 14, 2012); ISDA Comment Letter addressed to the Prudential Regulators (November 26, 2012); ISDA Comment Letter addressed to the Prudential Regulators (November 24, 2014); Managed Funds Association Comment Letter addressed to the Prudential Regulators (November 24, 2014).

[67] See Basel Committee on Banking Supervision & Board of the International Organization of Securities Commissions, Margin requirements for non-centrally cleared derivatives 22 (March 2014).

[68] See e.g. SIFMA Comment Letter addressed to the Prudential Regulators (March 12, 2014); ISDA Comment Letter addressed to the Prudential Regulators (November 26, 2012).

[69] See Margin and Capital Requirements for Covered Swap Entities,79 Fed. Reg. at 57,392.

[70] See Managed Funds Association Comment Letter addressed to the Prudential Regulators (November 24, 2014).

[71] See e.g. Managed Funds Association Comment Letter addressed to the Prudential Regulators (November 26, 2012); Managed Funds Association Comment Letter addressed to the CFTC (July 11, 2011); ISDA Comment Letter addressed to the Prudential Regulators (November 26, 2012).

[72] See Margin and Capital Requirements for Covered Swap Entities,79 Fed. Reg. at 57,395.

[73] See id. at 57,382.

[74] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,932.

[75] See, e.g., 17 CFR 23.504.

[76] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,932 & Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,388.

[77] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,932 & Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,389.

[78] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,932 & Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,388.

[79] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,932 & Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,389.

[80] See Basel Committee on Banking Supervision & Board of the International Organization of Securities Commissions, Margin requirements for non-centrally cleared derivatives 24 (2015)
available at  http://www.bis.org/bcbs/publ/d317.pdf.

[81] Philip Stafford, Hopes quashed of two-year delay for new swaps rules, Financial Times (Mar. 11, 2015), http://www.ft.com/intl/cms/s/0/15a8496e-c80e-11e4-8210-00144feab7de.html?siteedition=intl#axzz3UYwoM5Rn.

[82] See Margin and Capital Requirements for Covered Swap Entities, 79 Fed. Reg. at 57,395.

[83] See id.

[84] See id.

[85] See id.

[86] See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed. Reg. at 59,916.

[87] See e.g. ISDA / SIFMA Joint Comment Letter addressed to the CFTC (July 11, 2011); SIFMA Asset Management Group Comment Letter addressed to the Prudential Regulators (November 26, 2012); Managed Funds Association Comment Letter addressed to the Prudential Regulators (November 24, 2014).

[88] See e.g. ISDA / SIFMA Joint Comment Letter addressed to the CFTC (July 11, 2011); ISDA Comment Letter addressed to the Prudential Regulators (November 26, 2012); ISDA / SIFMA Comment Letter addressed to the Prudential Regulators (November 24, 2014).

[89] ISDA/ SIFMA Joint Comment Letter addressed to the Prudential Regulators (July 6, 2011).

By

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

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Harvey L. Reiter*

I.         Introduction

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

IV.         Conclusion

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[13] Japan Line, 441 U.S. at 448–49.

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

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

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

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

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

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

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

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

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

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

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

[25] See Helston, supra note 24.

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

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

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

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

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

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

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

[33] Id.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

By

The Status of Environmental Commodities Under the Commodity Exchange Act

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Matthew F. Kluchenek*

This article examines the role of the Commodity Futures Trading Commission (“CFTC”) in regulating transactions in environmental commodities, such as renewable energy certificates (“RECs”), emissions allowances, carbon offsets and carbon credits. The article examines the general role of the CFTC, the types of products subject to the CFTC’s jurisdiction, the basis for and scope of exclusions to the CFTC’s jurisdiction, and how commodity option transactions could be converted into swaps subject to the CFTC’s jurisdiction.

Ultimately, transactions in environmental commodities may qualify for the forward exclusion from the definition of “swap” under the Commodity Exchange Act[1] (“CEA”)—and thus not be subject to CFTC regulation—if the transactions satisfy certain requirements, the most important of which is the parties’ intent to physically settle each transaction. Such an exemption, however, is relatively narrow, and the active “trading” of an environmental commodity may jeopardize the use of the exemption.

I.         The Role of the Commodity Futures Trading Commission

A.        Jurisdiction and Mission of the CFTC

When Congress created the CFTC in 1974, it conferred upon the CFTC “exclusive jurisdiction” over commodity futures and options thereon.[2] Unless exempted, futures contracts and options thereon must trade on a commodity exchange that has been designated as a contract market—that is, an exchange or market—by the CFTC in order to be legal and enforceable.[3] By contrast, spot and forward transactions—in which the parties intend to make or take delivery of a commodity—are not generally subject to CFTC jurisdiction.[4]

Historically, the CFTC’s regulation of trading in environmental commodities has been relatively limited, but the agency has explored the scope of its boundaries with respect to such commodities. For example, while recognizing that other federal agencies may be better equipped to regulate allocation and recordkeeping requirements associated with the trading of such products, former CFTC Chairman Gary Gensler asserted that oversight by the CFTC of environmental commodities would give it additional experience regulating cash emissions contracts, and claimed that, should Congress seek to regulate cash markets for emission instruments, the CFTC would be well suited to carry out that function. According to Chairman Gensler:

In most respects, emissions contract markets operate no differently than the other commodity markets the CFTC regulates. While each contract – such as sulfur dioxide, soybeans, treasury bills or natural gas – presents its own unique challenges, the regulatory scheme is essentially the same. Carbon markets have similarities to several different markets that fall within our regulatory authority. For example, carbon allowances and offsets are similar to agriculture commodities in that there is a yearly “crop” and important programmatic regulations governing the nature of the product. At the same time, carbon contracts have similarities to financial products. For example, government-issued allowances and offset credits would be similar to Treasury-issued debt instruments. Futures contracts on Treasury debt are among the most actively traded CFTC-regulated products.[5]

Ultimately, Congress did not accept Chairman Gensler’s invitation, but did mandate the formation, via the Dodd-Frank Wall Street Reform and Consumer Protection Act[6] (“Dodd-Frank Act”), of an inter-agency working group to study the oversight of existing and prospective carbon markets.[7]

B.        Dodd-Frank Act

In 2010, Congress enacted the Dodd-Frank Act, which adopted sweeping changes to how the markets in the U.S. for over-the-counter derivatives, and the participants in those markets, are regulated. Many of those changes were implemented by amending the CEA. Through the Dodd-Frank Act, Congress issued a general directive to the CFTC of having as many “swaps” as possible cleared by regulated clearing entities in order to reduce “systemic risk” to the financial markets, and as many “swaps” as possible traded on regulated exchanges, or on or through other regulated entities, in order to increase transparency in the markets.[8] The Dodd-Frank Act thus makes it unlawful for a person[9] to enter into a “swap” without complying with the CEA and the numerous rules promulgated by the CFTC.[10]

The Dodd-Frank Act was important to the environmental commodity market in two respects, both of which are discussed more fully below: 1) it provided and confirmed the basis for excluding environmental commodities from the definition of “swap” and thus from regulation by the CFTC; and 2) it created the inter-agency working group to study the markets.

C.        The Definition of “Swap”

1.         Dodd-Frank Act

The cornerstone of commodity futures trading regulations under the Dodd-Frank Act is the definition of “swap.” Generally, if a transaction involves a swap, regulation follows. The Dodd-Frank Act contains a broad definition of “swap” that encompasses most transactions that transfer financial risk from one party to the other party.[11] The definition of swap specifies several categories, including:

  • Options, including puts, calls, caps, floors and collars;
  • Event contracts;
  • Swap structures in which a fixed payment is exchanged for a floating payment on one or more scheduled dates, with payments linked to the value or level of one or more rates, currencies, commodities, quantitative measures or other financial or economic interests, and which transfers risk associated with a future change in the value or level of the foregoing between the parties without also conveying a current or future ownership interest in an asset; and
  • Instruments that become commonly known to the trade as swaps or by more specific names linked to an underlying commodity or financial measure.[12]

2.         The CFTC’s Further Definition of “Swap”

In July 2011, the CFTC and the SEC adopted joint final rules further defining the term “swap” and other terms in the Dodd-Frank Act (“Product Release”).[13] The Product Release provides important guidance on the classification of various types of derivative instruments. These classifications determine whether the instruments are subject to regulation by the CFTC or the SEC (or both) or whether they fall outside of either agency’s general regulatory authority under the CEA, as amended by the Dodd-Frank Act.[14] As discussed below, the Product Release examines whether environmental commodities may be subject to federal regulation by the CFTC and the basis for any exemption.

II.        The Forward Exclusion

A.        Generally

Since its inception in 1936, the CEA has excluded so-called “forward contracts” from federal regulation. The CEA defines the term “forward contract” by excluding such contracts from the term “future delivery”—i.e., from the definition of futures contracts. The operative provision provides that “‘future delivery’ does not include any sale of any cash commodity for deferred shipment or delivery.”[15] This language provides the basis for the so-called “forward exclusion,” which refers to the exclusion of forward contracts from regulation under the CEA and the jurisdictional auspices of the CFTC.[16]

Notably, the Dodd-Frank Act amended the CEA to add a forward exclusion to the definition of “swap.”[17] The exclusion applies to “any sale of a nonfinancial commodityor security for deferred shipment ordelivery, so long as the transaction isintended to be physically settled.”[18] To fall within the exclusion, a transaction must include the following three components:

  • a nonfinancial commodity,
  • deferred shipment or delivery of the nonfinancial commodity, and
  • an intent to physically deliver the nonfinancial commodity.

The CFTC has stated that it intends to interpret the forward exclusion for nonfinancial commodities in the “swap” definition in a manner consistent with its historical interpretation of the existing forward exclusion with respect to futures contracts.[19] The CFTC’s historical interpretation has been that forward contracts are “commercial merchandising transactions,” the primary purpose of which is to transfer ownership of the commodity and not to transfer solely its price risk.[20]

B.        Nonfinancial Commodities

In the Product Release, the CFTC interpreted the scope of the term “nonfinancial commodity” in the forward exclusion. According to the CFTC, a “nonfinancial commodity” is a “commodity that can be physically delivered and that is an exempt commodity or an agricultural commodity.”[21] Exempt commodities, including energy commodities, metals and agricultural commodities, are nonfinancial by nature.

The requirement that a commodity be able to be physically delivered is designed to prevent market participants from relying on the forward exclusion to enter into swaps based on indexes of exempt or agricultural commodities outside the bounds of the Dodd-Frank Act and settling them in cash, which the CFTC believes would be inconsistent with the historical limitation of the forward exclusion to commercial merchandising transactions.[22]

C.        Intangible Commodities

The CFTC has interpreted the term “intangible commodity” to qualify as a nonfinancial commodity so long as “ownership of the commodity can be conveyed . . . and the commodity can be consumed.”[23] The CFTC has emphasized that, for an intangible commodity to qualify for the forward exclusion, there must be an intent to physically settle the transaction.[24] As discussed in greater detail below, an example of an intangible nonfinancial commodity that qualifies under this interpretation is an environmental commodity that can be physically delivered and consumed (e.g.,by emitting the amount of pollutant specified in the allowance).[25]

D.        Deferred Delivery

An essential element of a forward contract is that the delivery of the nonfinancial commodity is deferred.[26] Delivery is typically deferred for commercial convenience or necessity.[27]

To the extent that a transaction results in immediate or near-immediate delivery of the commodity, the contract is likely to be characterized as a “spot” transaction. The CEA excludes “spot” or “cash” transactions from the CFTC’s jurisdiction.[28] The CFTC staff has defined a spot transaction as one where immediate delivery of and payment for the product are expected on or within a few days of the trade date.[29]

According to the Sixth Circuit, “because the CEA was aimed at manipulation, speculation, and other abuses that could arise from the trading in futures contracts and options, as distinguished from the commodity itself, Congress never purported to regulate ‘spot’ transactions (transactions for the immediate sale and delivery of a commodity) or ‘cash forward’ transactions (in which the commodity is presently sold but its delivery is, by agreement, delayed or deferred).”[30] Accordingly, transactions in environmental commodities on a spot basis would not be subject to the CEA.

E.        Intent to Deliver

Because a forward contract is a commercial merchandising transaction, intent to deliver has been the critical element of the CFTC’s analysis of whether a particular contract is a forward contract.[31] In assessing the parties’ delivery intent, the CFTC has applied a “facts and circumstances” test in which the CFTC “reads the ‘intended to be physically settled’ language . . . to reflect a directive that intent to deliver a physical commodity be a part of the analysis of whether a given contract is a forward contract or a swap, just as it is a part of the CFTC’s analysis of whether a given contract is a forward contract or a futures contract.”[32]

A good example of the line of cases interpreting the intent to deliver requirement is CFTC v. Co Petro Mktg. Group, Inc.[33] In 1982, the Ninth Circuit considered a claim by the CFTC that Co Petro, an operator of retail gasoline outlets and a petroleum broker, was unlawfully selling off-exchange futures contracts, under which Co Petro sold petroleum “at a fixed price for delivery at an agreed future date,” but “did not require its customer to take delivery of the fuel.”[34] As explained by the Ninth Circuit, the customer could designate Co Petro, at a future date, to sell the fuel on its behalf and not take delivery of the fuel. If the cash price rose during the interim period, Co Petro would remit to the customer the difference between the original purchase price and the subsequent sale price. If the cash price decreased, Co Petro would deduct from the customer’s deposit the difference between the purchase price and the subsequent sale price and remit the balance of the deposit to the customer.[35]

The CFTC alleged that these transactions constituted transactions in futures and thus were required to be traded on an exchange subject to CFTC jurisdiction. In response, Co Petro contended that the CFTC did not have jurisdiction over the transactions because they constituted forward contracts and were thus expressly excluded from the CEA.[36]

Based upon the CEA’s legislative history, the Ninth Circuit concluded that Congress intended “that a cash forward contract is one in which the parties contemplate physical transfer of the actual commodity.”[37] In finding that the parties to the Co Petro agreements did not contemplate actual delivery in the future, the court of appeals held that the forward contract “exclusion is unavailable to contracts of sale for commodities which are sold merely for speculative purposes and which are not predicated upon the expectation that delivery of the actual commodity by the seller to the original contracting buyer will occur in the future.”[38]

Importantly, subsequent book-outs or alternative settlement methods generally will not alter the original character of the agreement as a commercial merchandising transaction so long as the original agreement contemplated physical delivery of the commodity.[39] In addition, the presence of certain provisions such as liquidated damages and renewal or evergreen provisions does not necessarily render an agreement ineligible for the forward exclusion.[41]

III.      Environmental Commodities

A.        Interagency Working Group’s Carbon Oversight Study

Prior to the issuance of the Product Release, the Interagency Working Group for the Study on Oversight Carbon Markets (“Interagency Working Group”), led by the CFTC, issued a report on the oversight of existing and prospective carbon markets (“Carbon Report”), fulfilling a requirement established in the Dodd-Frank Act.[41]

In its report, the Interagency Working Group recommended that the following four objectives guide the oversight of existing and prospective carbon markets:

  1. Facilitate and protect price discovery in the carbon markets.[42]
  2. Ensure appropriate levels of carbon market transparency.[43]
  3. Allow for appropriate, broad market participation.[44]
  4. Prevent manipulation, fraud and other market abuses.[45]

Based on its study, the Interagency Working Group issued the following recommendations in its report regarding the oversight of existing and prospective carbon markets:

  • Rely on the existing regulatory oversight program, as enhanced by the Dodd-Frank Act, for both existing and prospective carbon allowance and offset derivatives markets.[46]
  • Ensure that appropriate oversight mechanisms are in place for primary and secondary allowance and offset markets, reflecting the above objectives and the interdependence of primary, secondary and derivative carbon markets and any unique characteristics or circumstances of such markets.[47]

B.        Environmental Commodities Under the Forward Exclusion

Building on the findings and recommendations in the Carbon Report, the CFTC noted in its Product Release that the Carbon Report “suggested that the forward exclusion could apply to agreements, contracts or transactions in environmental commodities” such as emissions allowances, carbon offsets/credits and RECs.[48] The Carbon Report specifically states:

No set of laws currently exist that apply a comprehensive regulatory regime—such as that which exists for derivatives—specifically to secondary market trading of carbon allowances and offsets. Thus, for the most part, absent specific action by Congress, a secondary market for carbon allowances and offsets may operate outside the routine oversight of any market regulator.[49]

Further, in discussing environmental commodities, the CFTC noted in its release that it:

understands that market participants often engage in environmental commodity transactions in order to transfer ownershipof the environmental commodity (and not solely price risk), so that the buyercan consume the commodity in order to comply with the terms of mandatory or voluntary environmental programs.Those two features—ownership transfer and consumption—distinguish such environmental commodity transactions from other types of intangible commodity transactions that cannot be delivered, such as temperatures and interest rates. The ownership transfer and consumption features render such environmental commodity transactions similar to tangible commodity transactions that clearly can be delivered, such as wheat and gold.[50]

As a result, the CFTC found that “environmental commodities can be nonfinancial commodities that can be delivered through electronic settlement or contractual attestation. Therefore, an agreement, contract or transaction in an environmental commodity may qualify for the forward exclusion from the swap definition if the transaction is intended to be physically settled.”[51]

Conversely, as described by an industry participant, to the extent that emissions allowances, carbon offsets/credits and RECs are not physically settled (i.e., consumed), but traded in secondary market fashion like a stock or bond, the forward exclusion would likely not apply to the transaction.[52] Moreover, the CFTC has stated that, if a contract were to include the right to unilaterally terminate an agreement under a pre-arranged contractual provision permitting financial settlement, the forward exclusion would not apply.[53]

Importantly, the CFTC does have authority over forward contracts under the CEA’s anti-manipulation provisions prohibiting manipulation, making false and misleading statements and omissions of material fact to the CFTC, fraud and deceptive practices, and false reporting.[54]

IV.      Commodity Options

A.        Generally

To the extent that an environmental commodity transaction is structured as either a commodity option or is embedded with a commodity option, the contract may be subject to CFTC regulation. Further, commodity option contracts that function as “trade options” are subject to limited CFTC oversight.

B.        CFTC Jurisdiction over Commodity Options

Under the CEA, the CFTC has plenary authority to regulate commodity option transactions.[55] Commodity options are illegal unless and until the CFTC specifically authorizes them.[56] The CEA, as amended by the Dodd-Frank Act, defines the term “swap” to include “a put, call, cap, floor, collar, or similar option of any kind that is for the purchase or sale, or based on the value, of 1 or more . . . commodities.”[57] Options on physical commodities are included in the statutory definition of swap.[58]

Under the CFTC’s part 32 rules, any person is permitted to transact commodity options on or subject to the rules of a designated contract market, while only an eligible contract participant(“ECP”) is permitted to transact commodity options bilaterally or on a swap execution facility.[59]

C.        CFTC Jurisdiction over Trade Options

CFTC Rule 32.3 provides an exemption from certain of the swap regulations for trade options on exempt commodities (such as energy and metal commodities) and agricultural commodities (such as grain and soft commodities) if the parties to, and the characteristics of, the commodity options satisfy certain requirements.[60] In order to be eligible for the trade option exemption, three requirements must be met:

  1. the offeror of a commodity option must be either an ECP or a commercial market participant;
  2. the offeree must be a commercial market participant; and
  3. the commodity option must be intended to be physically settled, so that, if exercised, the option would result in the sale of an exempt or agricultural commodity for immediate or deferred shipment or delivery.[61]

While most of the CFTC’s swap rules do not apply to trade options, some rules do apply to each trade option counterparty.[62]

D.        CFTC Jurisdiction over Forward Contracts with Embedded Volumetric or Price Optionality

Under the CFTC’s interpretations, a forward contract may be considered a swap because it is embedded with optionality—either volumetric or price optionality. According to the CFTC, a transaction with volumetric optionality is a forward contract (i.e., not a swap) if it meets the following seven-part test:

  1. the embedded volumetric optionality does not undermine the overall nature of the agreement as a forward contract;
  2. the predominant feature of the agreement is delivery;
  3. the embedded volumetric optionality cannot be severed and marketed separately;
  4. the seller of the underlying nonfinancial commodity intends to make delivery of the commodity if the option is exercised;
  5. the buyer of the underlying nonfinancial commodity intends to take delivery of the commodity if the option is exercised;
  6. both parties are commercial parties; and
  7. the exercise or non-exercise of the embedded volumetric optionality is based primarily on physical factors or regulatory requirements that are outside the control of the parties.[63]

Further, the CFTC has stated that a contract embedded with price optionality is likely a forward contract (i.e., not a swap) if the option:

  1. may be used to adjust the forward contract price but does not undermine the overall nature of the contract as a forward contract;
  2. does not target delivery terms, so that the predominant feature of the contract is actual delivery; and
  3. cannot be severed and marketed separately from the overall forward contract in which the option is embedded.[64]

A contract with an embedded option that satisfies the applicable test(s) will qualify for the forward exclusion and will not be regulated as a swap. As with other transactions, whether price or volumetric options qualify for the forward contract exclusion will be based on overall facts and circumstances.[65]

Ultimately, to the extent that any contracts are deemed to be swaps because of embedded optionality, the full panoply of the CEA’s swap regulations would be triggered. In such a circumstance, the contract would be subject to the various clearing, execution, reporting and recordkeeping requirements under the CEA, and the parties to the transactions may be subject to registration, business conduct and numerous other requirements.[66]

 

Preferred citation: Matthew F. Kluchenek, The Status of Environmental Commodities Under the Commodity Exchange Act, 5 Harv. Bus. L. Rev. Online 39 (2015), https://www.hblr.org//?p=3939.

* Matthew F. Kluchenek is a Partner at Baker & McKenzie LLP, and heads the Firm’s North America Derivatives practice.

[1] Commodity Exchange Act of 1936, Pub. L. No. 74–675, 49 Stat. 1491 (1936) (codified as amended in scattered sections of 7 U.S.C.), replacing the Grain Futures Act of 1922.

[2] Commodity Futures Commission Trading Act of 1974, Pub. L. No. 93-463, 88 Stat. 1389 (1974) (codified as amended in scattered sections of 7 U.S.C.). The CEA does not define the term “futures” or “futures contract,” but such contracts are generally defined as standardized contracts to buy or sell a commodity for a specified price in the future. In a futures contract, only the price and the quantity of the contracts are negotiated; all of the other terms are standardized and not negotiable. Importantly, a futures contract does not involve the sale of a commodity, but the sale of a contract, which permits the purchaser to buy or sell the commodity (unless the contract is cash-settled). From a statutory perspective, Congress refers to “futures contracts” in the CEA as “transactions involving . . . contracts of sale of a commodity for future delivery.” 7 U.S.C. § 2(a)(1)(A) (2012). The CEA defines “contract of sale” broadly to include “sales, agreements of sale, and agreements to sell.” See id. § 1a(13). The term “future delivery” is defined as excluding “any sale of any cash commodity for deferred shipment or delivery.” Id. § 1a(27).

[3] Id. § 6(a).

[4] See Dunn v. CFTC, 519 U.S. 465, 472 (1997) (noting that forward contracts are agreements in which participants “anticipate the actual delivery of a commodity on a specified future date,” while spot contracts are “agreements for purchase and sale of commodities that anticipate near-term delivery”).

[5] Global Warming Legislation: Carbon Markets and Producer Groups Before the S. Comm. on Agriculture, Nutrition, and Forestry, 111th Cong. 3 (2009) (statement of Gary Gensler, Chairman, Commodity Futures Trading Comm’n).

[6] Pub. L. No. 111-203, 124 Stat. 1376 (2010) (codified as amended in scattered sections of 7, 12, and 15 U.S.C.).

[7] See Dodd-Frank Act § 750.

[8] See 7 U.S.C. §§ 2(h)(1)(A), 2(h)(8)(B).

[9] Under 7 U.S.C. § 2(e), each counterparty to a swap transaction that is not executed on or pursuant to the rules of a designated contract market is required to be an “eligible contract participant,” or “ECP.” The definition of ECP is set forth in 7 U.S.C. § 1a(18), and 17 C.F.R. § 1.3(m) (2014).

[10] See, e.g., 7 U.S.C. §§ 2(h), 2(h)(8)(B).

[11] See 7 U.S.C. § 1a(47)(A).

[12] See id.

[13] 77 Fed. Reg. 48,208 (Aug. 13, 2012).

[14] See id.

[15] 7 U.S.C. § 1a(27) (emphasis added).

[16] The “forward exclusion” has a lengthy history, originating in the Futures Trading Act of 1921 (“FTA”), Pub. L. No. 67-66, ch. 86, 42 Stat. 187 (1921) (held unconstitutional by Hill v. Wallace, 259 U.S. 44 (1922)). As proposed by Congress, the FTA sought to impose a tax on futures contracts—a term not defined in the FTA. During the bill’s Congressional hearings, however, farmers expressed concern over the possible taxation of forward transactions, which farmers replied upon as a critical commercial hedging tool. See Hearing on H.R. 5676 Before the S. Comm. on Agriculture and Forestry, 67th Cong. 8-9, 213-14, 431, 462 (1921); CFTC v. Co Petro Mktg. Group, 680 F.2d 573, 577 (9th Cir. 1982). In response, the Senate added a provision to the FTA that excluded from the definition of “future delivery” “any sale of cash grain for deferred shipment or delivery.” See Pub. L. No. 67-66, 42 Stat. 187. According to the Senate report, the “addition was made in order that transactions in cash grain when made for deferred shipment or delivery, would not fall within the provisions for taxing imposed in Section 4 of the bill.” S. Rep. No. 212, at 1 (1921). In discussing the scope of the provision, Senator Capper, the bill’s sponsor, made clear that “the bill does not concern itself at all with the sale or purchase of actual grain, either for present or future delivery. The entire business of buying and selling actual grain, sometimes called ‘cash’ or ‘spot’ business, is expressly excluded. It deals only with the ‘future’ or ‘pit’ transaction, in which the transfer of actual grain is not contemplated.” 61 Cong. Rec. 4762 (1921) (statement of Sen. Capper). The cash forward exclusion was carried forward without change into the Grain Futures Act of 1922, Pub. L. No. 67-331, § 2(a), ch. 369, 42 Stat. 998 (1922), which replaced the FTA, and thereafter was incorporated into the CEA, 7 U.S.C. § 1a(27). The language remains unchanged from inception through today.

[17] See id. § 1a(47)(B).

[18]Id.§ 1a(47)(B)(ii).

[19] See 77 Fed. Reg. at 48,227.

[20] See id. at 48,235 (“[A] transaction entered into by a consumer cannot be a forward transaction.”).

[21] Id. at 48,232. The CEA defines an “exempt commodity” as “a commodity that is not an excluded commodity or an agricultural commodity.” 7 U.S.C. § 1a(20). The CFTC defines the term “agricultural commodity” in Rule 1.3(zz). See 76 Fed. Reg. 41,048, 41,056 (Jul. 13, 2011).

[22] See 77 Fed. Reg. at 48,232.

[23] See id. at 48,233 (emphasis added).

[24] See id.

[25] See id.

[26] See 7 U.S.C. § 1a(27).

[27] See 77 Fed. Reg. at 48,228.

[28] See Commodity Futures Trading Comm’n, Div. of Trading & Markets, CFTC Letter No. 98-73 (Oct. 8, 1998) (stating the CEA “does not provide the Commission with jurisdiction over true ‘spot’ transactions”).

[29] See id. (“In a spot transaction, immediate delivery of the product and immediate payment for the products are expected on or within a few days of the trade date.”).

[30] CFTC v. Erskine, 512 F.3d 309, 321 (6th Cir. 2008).

[31]The CFTC observed in its decision inWright that “it is well-established that the intent tomake or take delivery is the critical factor indetermining whether a contract qualifies as aforward.” Wright, CFTC Docket No. 97–02,2010 WL 4388247 at *3 (Oct. 25, 2010).

[32]Further Definition of “Swap;” “Security-Based Swap Agreement”; Mixed Swaps; Security-Based Swap Agreement Recordkeeping, Securities Act Release No. 9204,Exchange Act Release No. 64372 [FSLR Transfer Binders—2002 to Current] Fed. Sec. L. Rep. (CCH) ¶ 89,429 (April 29, 2011). See also Andersons, Inc. v. Horton Farms, 166 F.3d 308, 318-17 (6th Cir. 1998) (“The purpose of this ‘cash forward’ exception is to permit those parties who contemplate physical transfer of the commodity to set up contracts that (1) defer shipment but guarantee to sellers that they will have buyers and vice versa, and (2) reduce the risk of price fluctuations.”).

[33]680 F.2d 573, 576 (9th Cir. 1982).

[34]Id.

[35]Id.

[36]Id. at 576-77.

[37]Id. at 578 (emphasis added).

[38]Id. at 579. However, while most courts have adopted the CFTC’s reasoning, in CFTC v. Zelener, 373 F.3d 861, 865 (7th Cir. 2004), the Seventh Circuit (and several lower courts) disregarded any intent or physical delivery consideration. Rather, the Seventh Circuit held that the relevant inquiry was whether the transaction involved “a sale of the commodity,” in which case it would be deemed to be a forward contract, or whether the contract was “a sale of the contract,” in which case it would be considered a futures contract. As a proxy for such an inquiry, the court looked to whether the contract was fungible or, absent fungibility, whether the seller promised to allow the buyer to enter into an offsetting contract on demand. If either condition applied, the contract would be regarded as a futures contract. Id. at 868. Nonetheless, the CFTC has continued to adhere to the intent to deliver requirement, as evidenced in the Product Release and subsequent CFTC enforcement actions.

[39] See 77 Fed. Reg., at 48,227-32.

[40] Id. at 48,240.

[41]See Interagency Working Group for the Study on Oversight of Carbon Markets, Report on the Oversight of Existing and Prospective Carbon Markets (Jan. 2011) [hereinafter Carbon Report], http://www.cftc.gov/ucm/groups/public/@swaps/documents/file/dfstudy_carbon_011811.pdf. The interagency group is composed of the following members: the Chairman of the CFTC, who serves as the group’s Chairman, the Secretary of Agriculture, the Secretary of the Treasury, the Chairman of the Securities and Exchange Commission, the Administrator of the Environmental Protection Agency, the Chairman of the Federal Energy Regulatory Commission, the Chairman of the Federal Trade Commission and the Administrator of the Energy Information Administration.

[42] Id. at 49.

[43] Id. at 50.

[44] Id.

[45] Id.

[46] Id. at 51.

[47] Id.

[48] 77 Fed. Reg. at 48,233 n.277. The CFTC chose not to define the term “environmental commodity” because “any intangible commodity—environmental or otherwise—that satisfies the terms of the interpretation [in the Product Release] is a nonfinancial commodity, and thus an agreement, contract or transaction in such a commodity is eligible for the forward exclusion from the swap definition.” Id. at 48,233. Regarding a REC, for example, the commission reasoned the “forward sale of a REC transfers ownership of the REC from the producing entity to another entity that can use the REC for compliance with an obligation to sell a certain percentage of renewable energy. Many times, this forward sale takes place prior to the construction of a project to enable developers to secure related project financing.” Id. at 48,233 n.285.

[49] Carbon Report, supra note 28, at 42.

[50] 77 Fed. Reg. at 48,233–34 (emphasis added). The CFTC has previously indicated that environmental commodities can be physically settled. Id. at 48,233 n.277.

[51] 77 Fed. Reg. at 48,234 (emphasis added).

[52] See id. at 48,235 n.291 (citing a comment letter explaining that, “unlike a stock or a bond, which can be resold for its cash value, purchasers of environmental commodities intend to take delivery of RECs or carbon offsets for either compliance purposes or in order to make an environmental claim regarding their renewable energy use or carbon footprint”); see generally, 77 Fed. Reg. at 48,233-35.

[53] See id. at 48,235 n.292.

[54] See, e.g., 7 U.S.C. § 12(d) (directing the CFTC to investigate the marketing conditions of commodities and commodity products and byproducts); id. §§ 9, 13b, 13(a)(2), 15 (proscribing any manipulation or attempt to manipulate the price of any commodity in interstate commerce and enabling the CFTC to take action against violators). In particular, the CEA prohibits any person to (i) “use or employ, or attempt to use or employ . . . any manipulative or deceptive device or contrivance”; (ii) “make any false or misleading statement of material fact” to the CFTC or “omit to state in any such statement any material fact that is necessary to make any statement of material fact made not misleading in any material respect”; and (iii) “manipulate or attempt to manipulate the price of any swap, or of any commodity in interstate commerce.” Id. § 9(1)-(3); see also 17 C.F.R. § 180.1(a) (prohibiting manipulation, false or misleading statements or omissions of material fact, fraud or deceptive practices or courses of business, and false reporting in connectionwith any swap, or contract of sale of any commodity in interstate commerce).

[55] See 7 U.S.C. § 6c(b).

[56] See 17 C.F.R. § 32.2.

[57] See id. § 1a(47), amended by the Dodd-Frank Act § 721.

[58] See id.

[59] See 17 C.F.R. § 32.3(a)(1)(i).

[60] 17 C.F.R. § 32.3.

[61] Id. § 32.3(a).

[62]Such applicable regulations include: part 20 (large trader reporting); part 151 (position limits); subpart J of part 23 (duties of swap dealers and major swap participants); sections 23.200 through 23.204 (reporting and recordkeeping requirements for swap dealers and major swap participants); and section 4s(e) of the CEA (capital and margin requirements for swap dealers and major swap participants). Id. § 32.3(c)(1)-(5). Each counterparty to a trade option must comply with recordkeeping and reporting requirements under part 45. Id. § 32.3(b).

[63] Commodity Futures Trading Commission, CFTC Division of Market Oversight Responds to Frequently Asked Questions Regarding Commodity Options—Commodity Options FAQ (Sept. 2013), https://forms.cftc.gov/_layouts/TradeOptions/Docs/TradeOptionsFAQ.pdf; see also 77 Fed. Reg. at 48,238-40.

[64] Id.

[65] Id.  On November 20, 2014, the CFTC published a proposed interpretation that would clarify the CFTC’s views with respect to forwards with embedded volumetric optionality.  See 79 Fed. Reg. 69,073 (Nov. 20, 2014).  The proposal targets the seventh element of the volumetric optionality test.  In this respect, the CFTC would delete the reference to “the exercise or non-exercise” of the option, which would clarify that the focus of this element is on the intent of the parties, rather than the exercise or non-exercise of the option.  The proposal would also delete the requirement that the “physical factors or regulatory requirements” be outside the control of the parties.  Id. at 69,075-76.  Thus, if ultimately approved by the CFTC, the seventh factor would read: “The embedded volumetric optionality is primarily intended, at the time that the parties enter into the agreement, contract, or transaction, to address physical factors or regulatory requirements that reasonably influence demand for, or supply of, the nonfinancial commodity.”  Id. at 69,074.  If enacted, such language would represent a significant improvement over the CFTC’s extant interpretation.

[66] See, e.g., 7 U.S.C. § 2(a) (recordkeeping and reporting requirements); § 2(h) (clearing mandate); § 2(h)(8) (trade execution mandate); § 6s(h) (business conduct requirements); § 6s(e) (margin and capital requirements).

By

The Regulatory Challenge Of Distributed Generation

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David B. Raskin*   

I.   Introduction

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

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

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

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

II.   Net Metering: The Current Battlefield

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

III.   The Return of Stranded Costs

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

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

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

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

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

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

A.  Cost Recovery for Regulated Assets

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

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

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

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

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

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

B.  Unregulated Generation

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

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

IV.   Conclusion

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

 

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[24] Id. at 110.

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

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

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

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

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

[30] Id. at 650.

[31] Id.

[32] Id. at 652.

[33] Id.

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

[35] 18 C.F.R. § 292.203(d) (2010).

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

[37] 16 U.S.C §§ 791a-825r.

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

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

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

[41] Id.

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

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

[44] 16 U.S.C. § 824e(a).

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

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

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

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

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

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

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

[52] Id. at 605.

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Opportunities for Solar Generation: Pipeline Infrastructure Synergies

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

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

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

 

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

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

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

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

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

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

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

[6] Id. at 12.

[7] Id.

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

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

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

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

[12] Id.

[13] See id.

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

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

[16] See I.R.C. § 7704(c)(1) (2012).

[17] See id. § 701.

[18] See id. § 11.

[19] See id. § 61(a)(7).

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

[21] Id. at 2313-683.

[22] I.R.C. § 7704(c)(2) (2012).

[23] See id. § 7704(d).

[24] See id. § 7704(d)(1)(e).

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

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

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

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

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

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

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

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

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

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Stephen Heifetz and Michael Gershberg*

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

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

CFIUS Background

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

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

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

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

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

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

The Rise of China

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

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

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

Infrastructure Vulnerability

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

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

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

Changing Balance Within CFIUS

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

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

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

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

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

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

Conclusion

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

 

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

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

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

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

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

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

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

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

[7] See 50 U.S.C. app. § 2170(k).

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

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

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

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

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

[13] 50 U.S.C. app. § 2170(d)(1).

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

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

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

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

[18] Id. § 800.401(b).

[19] Id. § 800.401(c).

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

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

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

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

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

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

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

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

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

[29] Id. § 4.

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

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

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

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

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

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

[36] See Bathon, supra note 3.

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

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

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

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

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