On July 21, 2016, the Federal Energy Regulatory Commission (“FERC”) issued a Notice of Proposed Rulemaking (“NOPR”) titled Data Collection for Analytics and Surveillance and Market-Based Rate Purposes. The NOPR is intended to collect certain market data from market-based rate (“MBR”) electricity sellers, incorporating data about their affiliates, including natural gas and electricity companies (“Connected Entities”). As FERC increases its emphasis on market surveillance, the NOPR appears to be tailored to bring to light any corporate or financial connections that may exist among various market participants involved in buying, selling, transporting, or producing natural gas, electricity, and coal. The NOPR provides, in relevant part, that “the Commission observed that there is a risk that a market participant may take actions to benefit another entity that bears a financial or legal relationship to it, and that entities under common control may collude to manipulate the market. Given the potential for such conduct, the Commission found it needed to understand the relationships and corresponding incentives between entities to help determine whether they might be engaging in acts of market manipulation.” This emphasis on cross-affiliate and cross-commodity activity is consistent with recent regulatory scrutiny by energy regulators. Consequently, the information required to be reported by the NOPR would allow FERC’s staff to monitor a large number of trades, physical and financial, and cross-reference any unauthorized or suspicious activity.
The NOPR includes two different and somewhat overlapping reporting requirements. The first reporting requirement is MBR-related information. In particular, FERC intends to use this type of information to determine whether market participants should be permitted to obtain or maintain a market-based rate. This information would include an evaluation of market participants’ and their affiliates’ horizontal and vertical market power. This type of information gathering is very similar to what FERC already requires from market participants seeking an MBR. The second group of reporting requirements is related to market surveillance and analytics, i.e., the potential for market manipulation (“Connected Entity information”). The NOPR emphasizes that “screening market activity for anomalies must include understanding the circumstances surrounding a given pattern of trading, including the possible motivations for that behavior, which can sometimes be found in the legal or contractual relationships entities bear to one another.” The NOPR’s Connected Entity information requirements apply not only to the MBR holders but, also, to any affiliated entity that trades virtual products or financial transmission rights (“FTR”). The NOPR’s reporting requirement would not apply to municipal and cooperative entities.
Some of the information required to be reported under the NOPR includes the following:
- The “Connected Entity Ownership” – the identity of an MBR holder’s affiliates that: (a) are ultimate owners; (b) participate in organized wholesale electric markets; or (c) purchase or sell financial natural gas or electric energy derivative products that settle off the price of electric or natural gas energy products, which would, arguably, include any entity in the MBR holder’s enterprise, including the foreign based entities that trade in any financial products on ICE, CME, or NGX.
- Information about an MBR holder – as an electricity seller, such as category status for each region in which the reporting entity has MBR authority, markets in which it is authorized to sell ancillary services, mitigation, if any, and whether it has any limitations in the regions in which it has MBR authority.
- MBR “Ownership” information – this information would include affiliate owners that are: (a) ultimate affiliate owners and (b) affiliate owners that have a franchised service area or MBR authority or directly own or control generation, transmission, intrastate natural gas transportation, storage or distribution facilities, physical coal supply sources, or ownership of or control over who may access transportation of coal supplies.
- “Connected Entity Trader” and “Contracts information” – connected entity trader information would include any employees within an MBR holder’s connected entity, i.e., affiliates, that participate in making day-to-day trading decisions. Contracts information would include any entities that have entered into an agreement with the MBR holder that “confers control over an electric generation asset that is used in, or offered into, wholesale electric markets.” Agreements that confer control are those that grant one of the parties the right to make trading decisions for an electric generation asset of another party or to offer an electric generation asset into the wholesale electric markets.
- Asset ownership information – identifying the location, capacity, and percentage of ownership of electric generation and transmission assets and any assets that are owned or controlled by any MBR holder’s affiliate that does not have MBR authority. This would include any MBR holder’s affiliated entity that owns, actively or passively, any generation assets, or parts of those assets, including any joint ventures or special purpose entities.
The NOPR does not provide any empirical rationale for such a sweeping data harvest. In other words, it is unclear how often any type of cross-affiliate misconduct does occur in the market place and how frequently this type of misconduct rises to a level of a prohibited or manipulative outcome such as inappropriately influencing a price formation or operational reliability of the market as a whole. The very possibility that some market participants may do something, without any specific data indicating the frequency or severity of actual misconduct, makes it unclear if the associated costs of compliance, imposed on all MBR holders and their affiliates, are adequate and reasonable. To that end, there is a risk that this NOPR may appear to be a solution in search of a problem, rather than a problem in search of a solution.
If adopted as a final rule, the NOPR would impact many energy companies, especially those that engage in a diversified type of energy activities such as producing, transporting, processing, and marketing of electricity, natural gas, and coal. Given the traditional silo approach to many energy companies’ operational and financial functionality, it would be imperative to ensure an enterprise-wide approach to ensure compliance with the NOPR. This would include a strong risk management policy to ensure that any trading strategy approved by the senior management includes a cross-affiliate and/or cross-commodity vetting process to ensure that all trades stand on their own economics and, also, to prevent any prohibited trading conduct. The costs of the NOPR’s implementation are difficult to anticipate because they may include a significant cross-affiliate effort to create, train, and implement a variety of compliance steps including reconciling risk systems, trade-capture procedures, scheduling or dispatch activities, trading policies and procedures, and cross-affiliate system integration. The NOPR provides a 45-day comment period after it is published in the Federal Register.
On July 13, 2016, a federal judge in Chicago, IL sentenced a commodity trader to three years in prison for violating a Dodd-Frank prohibition against “spoofing.” The trader in question was convicted in a criminal case that followed a settlement order with the CFTC. The criminal conviction represents the first prison term handed down to a commodity trader since Dodd-Frank was enacted six years ago. The relevant portion of Dodd-Frank provides that it is “…unlawful for any person to engage in any trading, practice, or conduct on or subject to the rules of a registered entity that is, is of the character of, or is commonly known to the trade as, ‘spoofing’ (bidding or offering with the intent to cancel the bid or offer before execution).” The trader in question, and his company Panther Energy Trading LLC, were accused by the CFTC of placing bids or offers for crude oil, natural gas, and agricultural futures, on one side of the market to give the impression of market interest on that side of the market and to increase the likelihood that their smaller orders sitting on the opposite side of the market would be filled and using an algorithm designed to cancel the large bids or offers prior to execution. In other words, the trader was convicted of manipulating the markets by making large bids or offers he did not intend the fill and then entering into smaller trades on the opposite side of the market.
While spoofing was made illegal under Dodd-Frank, similar conduct had been occasionally used, in one form or another, for a long time. While it was considered unethical and discouraged by most market participants, there was never a common consensus about what exactly were the boundaries of legitimate price discovery trades as opposed to intentionally sending a false signal to the market and causing a price movement that does not reflect market fundamentals, i.e., supply and demand. For example, energy traders with a naturally long position such as crude oil, natural gas, or electricity producers often start their trading by entering into a smaller long positions to test the depth of the market. This has been a common practice for many decades and was considered a legitimate price discovery tool. However, with broad and vague anti-disruptive and anti-manipulation regulations under Dodd-Frank, energy marketers must carefully evaluate some of their trading practices.
The key takeaways from this case are twofold. First, the CFTC intends to vigorously enforce market regulations. Second, all market participants must provide their marketers with adequate resources to ensure that they only execute legitimate trades consistent with the current regulations. This means that in addition to regular training, all market participants should have robust policies and procedures outlining the management approved trading or hedging strategies, products, and exposure parameters. Also, the policies and procedures should ensure that the front office personnel are accountable for identifying and properly vetting any trades that may fall into the gray area. From a practical standpoint, those market participants that only occasionally trade have a much steeper learning curve because they are less likely to have a robust trading infrastructure. For example, energy producers, transporters, and distributors, whose core business is not trading, are more likely to be at risk. The cost of non-compliance with market regulations is so significant that there should be no doubt that every market participant must take the necessary measures to minimize the regulatory risk as much as possible. The challenge will be, as always, to ensure that regulatory compliance is structured in such a way to allow the uninterrupted business flow.
Energy market participants face an uphill battle in developing, maintaining, and implementing a set of consistent and current risk management or trading policies and procedures (together referred to as a “risk management policy” herein). Since most physical energy market participants are primarily focused on producing, transporting, distributing, or consuming energy commodities, their policy emphasis traditionally has been focused on operational reliability and safety. However, with the introduction of the Dodd-Frank Act (“DFA”), the majority of physical energy market participants, at least those that intend to hedge any of their positions, are required to create and maintain “…written policies and procedures that are reasonably designed to ensure that the persons responsible for evaluating all swap recommendations and making trading decisions…” on behalf of a company are capable of doing so. In addition to energy regulators, many exchanges also require that market participants include some specific exchange-related requirements in their policies and procedures such as position limits, block trades, prohibitions on wash trades, anti-disruptive trading practices, and other prohibited conduct.
The accelerated emphasis on corporate policies and procedures, in the energy arena, was initially triggered by the alleged misconduct and resulting exposures surrounding the Western energy crisis of 2000 – 2001. The rampant price volatility, unpredictable commodity exposure fluctuations, lack of adequate hedging, and regulatory uncertainty surrounding the Western energy crisis resulted in significant market dislocation, at least on the physical side. The speed of trading and associated defaults had been unprecedented, and many market participants were unprepared to quickly react to rapidly deteriorating market conditions. Subsequent investigations and reviews uncovered a significant breakdown of basic internal controls and corporate oversight, combined with improper compensation packages for some traders which incentivized and encouraged irresponsible trading practices. With that in mind, the Energy Policy Act of 2005, and subsequent policy statements by energy regulators, recommended that market participants develop and implement policies and procedures outlining the framework within which trading and risk management activities should take place while creating and maintaining a culture of compliance. However, the DFA is the first federal statute that specifically provides what must be included in a risk policy.
The main reason the DFA mandates a risk policy for energy companies and other “end users”, is to ensure that less-sophisticated (from the trading standpoint) market participants have the necessary skill set to properly understand and manage the risks associated with energy trading or hedging. In other words, the more market participants elevate their risk management skills, the more market fundamentals will remain stable and consistent. A risk policy allows every market participant to adequately outline the scope of its activities, approved trading/hedging strategies, approved products and markets, acceptable VaR and exposure limits, and the relevant corporate responsibility and accountability, from the board down to senior management. Also, it is critical for every market participant to properly outline the prohibited trading practices so the commercial personnel can stay away from any trading practice that could be deemed a market manipulation. A trader that is not properly trained and informed about what constitutes a market manipulation, disruptive trading practices, or similar trading misconduct, is much more likely to violate those rules. If a market participant is subject to a regulatory inquiry, its risk policy would probably be one of the documents that a regulator would want to review because that is the document that should reflect how seriously the company’s senior management, including its board, is committed to regulatory compliance. The tone is set at the top when it comes to regulatory compliance and the way that tone is manifested is in the risk policy.
While the overall reasons for creating and maintaining a robust risk policy seem obvious, many energy companies are struggling to adequately formulate their risk policy. There are several reasons for this. Energy utilities traditionally did not develop a robust marketing or risk management infrastructure, especially since their wholesale marketing or hedging activity was mostly incidental to their core business of managing the load for their residential or commercial customers. Also, many energy utilities’ senior executives and board members were suspicious of any significant wholesale marketing or hedging activities, mainly due to their lack of familiarity with these types of activities. Consequently, many energy utilities were behind the curve when it came to creating or maintaining a robust risk management skill set. This, in turn, made it more difficult to attract and retain adequate personnel, and utilities were often forced to reassign their employees, mainly engineers, to various marketing roles. This history of not focusing on a robust risk management infrastructure is now creating significant regulatory and financial exposure for many energy utilities, for several reasons.
First, gas and electric utilities cannot properly evaluate and manage the lowest wholesale supply costs for their customers without having the relevant risk management skill set. At the same time, participation in wholesale markets is becoming increasingly risky due to increased and vague market regulations. Consequently, many utilities trying to lower the wholesale supply costs to their customers could expose those same customers to significant risk if those utilities are authorized to pass any regulatory fines onto their customers. To manage this apparent dichotomy, it is imperative for utilities to create, implement, and continuously update their comprehensive risk policy in order that all relevant employees have clear understanding of their company’s risk framework and procedures for identifying, quantifying, and managing the commodity risk.
As a matter of course, gas and electric utilities emphasize their mission to keep their ratepayers’ rates as low as possible. Often they are required by their state utility commission to utilize certain risk management practices, such as hedging, to keep their rates as low as possible. This commitment to the ratepayers or state regulatory commissions is becoming increasingly difficult and risky to implement. For example, for a gas or electric utility to demonstrate that it has properly evaluated and executed the necessary risk management due diligence to keep the wholesale supply of commodity at the lowest possible price, including any hedging activity, it must have a risk policy that sufficiently outlines the risk management framework while ensuring that the utility’s core business mission is not overshadowed by the appearance of wholesale trading or hedging activities. Additionally, many utilities have to walk a fine line between their ratepayers’ need for low rates and their shareholders preference for a steady, fee based, cash flow, devoid of any volatility associated with wholesale marketing and trading activities. In order to properly demonstrate that they have ensured their ratepayers’ low rates by monitoring and reacting to changing wholesale market fundamentals, utilities must have a risk policy that adequately outlines a sequence of events for various marketing or hedging activities including price curves and models, position limits, authorized trading/hedging products, margin and collateral management, and prohibited trading practices. This, in turn, requires resources to hire and maintain personnel sufficiently trained and knowledgeable about marketing and hedging.
Another reason energy companies are now faced with increased exposure is the numerous layers of vague, often contradicting, and ever-expanding energy regulations make it increasingly difficult to formulate and implement a robust risk policy even for the most sophisticated market participants, let alone for physical energy companies such as gas and electric utilities. As energy commodities regulation became collateral damage to the sweeping Dodd-Frank regulation, it became evident that all market participants needed to elevate their risk management prowess, no matter how infrequently they participated in the wholesale market. Consequently, those market participants that only occasionally participated in the wholesale trading or hedging activities, such as energy utilities, faced a much steeper learning curve in creating and implementing adequate risk management framework. In addition to Dodd-Frank, many CFTC and FERC regulatory enforcement policy statements, recent enforcement cases and orders, various exchanges’ rules, and even U.S. Sentencing Guidelines reiterate the need for relevant risk management policies and procedures. At the same time, market participants face significant (civil and criminal) penalties for violating energy trading regulation. For example, a market participant can face up to $1 million per day, for market manipulation.
Every market participant should have a risk policy informing the relevant personnel to never engage in any prohibited marketing practices such as manipulation, wash trades, prohibited pre-arranged trades, noncompetitive trades, accommodation trades, fictitious trades, impermissible sleeves, prohibited trading in constrained markets, trading at off-market prices, trading at the close, pegging or supporting existing prices, uneconomic trading, misleading, false, or inaccurate reporting, recordkeeping requirements (including company, regulatory exchange, and all other requirements), false price reports, false statements, and anti-disruptive trading practices. Unfortunately, a prohibited conduct is often a matter of interpretation based on the “totality of circumstances.” For example, in a recent enforcement case, the CFTC fined a market participant for attempting to benefit its financial positions by uneconomic trading of fixed-price physical contracts, and pointed out that the market participant’s risk management department never questioned or disciplined traders for having a high market share at any particular hub location. While this statement was made by the CFTC in a particular context, the question remains how can any market participant identify a particular market share limitation for its traders, especially in light of real-time trading information? In particular, recent pullback in commodity prices has seen a significant decrease in liquidity at many trading points. Consequently, market participants that comprise a relatively small percentage of trading activity at those delivery points could suddenly gain a significant market share just by virtue of many other market participants dropping out. It may be impossible for the remaining market participants to measure their market share at those delivery points, especially if they have physical delivery obligations to meet. Thus, framing this issue in terms of a proactive risk policy could be very difficult.
Finally, another factor creating regulatory and financial exposure is the fact that the costs associated with establishing and maintaining a robust risk management program, including a risk policy, combined with the severity of potential fines and penalties for violating the regulation, may be cost-prohibitive to many energy utilities. In particular, any savings realized to the ratepayers by utilities’ hedging programs could be significantly smaller than the costs of creating and maintaining the risk management aspects of the utilities’ business. Also, the utilities ratepayers could end-up having to pay for any significant regulatory violations. Therefore, gas and electric utilities are facing a difficult choice of having to minimize the costs to their ratepayers’ and ever-increasing risk management regulatory risk. To the extent that they decide to participate in the wholesale market place, no matter infrequently, they are required to have the necessary risk policies and procedures in place.
In addition to utilities, other physical energy companies face similar challenges in balancing their core business activities with burdensome regulatory requirements. For example, a merchant generator trying to optimize a generation asset must carefully outline its risk management and trading/hedging activities to ensure that its marketing personnel do not engage in any marketing activity that could raise a regulatory red flag. Unfortunately, many prohibited marketing activities fall into a gray area where a market participant may face regulatory scrutiny and great cost just to prove that it did not do anything wrong. The increasing sentiment among energy market participants–that they are deemed guilty of a regulatory violation until they are proven innocent–is creating a difficult choice for many: either curtail business activities due to regulatory uncertainty or allocate significant resources to establishing a significant risk management infrastructure. This is a tough choice in any business environment but, it is especially tough in the time of depressed commodity prices and margins. Similar to merchant generators, a natural gas gathering company or pipeline is facing a similar dilemma. What makes their circumstances even more complicated, many natural gas gathering companies, pipelines, or storage providers are subject to either federal or state regulators, limiting their rates of recovery and mandating their market behavior. On top of that extensive operational and regulatory mandate, they also have to carefully navigate the wholesale marketing and risk management aspects of their business, no matter how infrequent it may be. For example, a natural gas gathering company must move the natural gas it receives from a producer, no matter what the market conditions may be. The flow of gas must continue in order for producers to meet their contractual obligations to royalty owners and other market participants. However, even a traditional natural gas service company such as gathering company, pipeline, or a gas processing facility is now required to comply with a plethora of risk management or trading regulation, no matter how infrequently they may participate in the wholesale market. In other words, they are expected to meet the extensive requirement regarding risk management prowess that can only be memorialized in a risk policy. Again, this can be a very expensive proposition in any market environment but, it is especially expensive in the depressed markets.
Considering the recent regulatory guidance and enforcement cases, it is clear that every market participant is expected to allocate sufficient resources to ensure that risk management systems allow to properly identify, quantify, and manage wholesale trading or hedging risk, no matter how frequently such market participant transact in a wholesale market. In addition, all market participants should continuously reiterate that all personnel at the company need to be committed to regulatory compliance to ensure the company’s conduct conforms to the relevant regulatory requirements including FERC, CFTC, and exchanges. This means communicating to all trading/marketing/hedging employees that they must comply, at all times, with the company’s risk policies regarding: authorized transactions, parameters and controls, restricted and prohibited activities, prohibitions against concealing trades, possible disciplinary actions, and required employees acknowledgements of compliance. These compliance goals should be memorialized in a proper risk policy, drafted to adequately balance the necessary compliance without unnecessarily constraining the day-to-day business objectives.
To be clear, having a robust risk policy is not, in itself, a guaranty of regulatory compliance. Many recent enforcement cases and orders have been issued against sophisticated market participants that, arguably, had some of the strongest risk management policies and procedures. A risk policy is only good if the relevant employees are directed, incentivized, and accountable to comply with it. The effectiveness of a risk policy must be measured by, among other things, making clear to management its responsibility to report to the board any “red flags” or other signs of improper conduct or questionable risk; overseeing management’s involvement in and commitment to a risk policy; scrupulously adhering to the policy; and considering an employee’s compliance with policy and relevant regulations in that employee’s compensation, promotion, and disciplinary action.
There should be no doubt that any energy company that participates in energy trading activity, however small, must have a robust risk policy. Recent regulatory enforcement cases have imposed significant monetary fines on companies and individuals involved in violations of energy regulations. The increased regulatory scrutiny on individual responsibility of traders and senior management makes it clear that every market participant must create the necessary risk management infrastructure, including a robust risk policy, to adequately protect the company, its employees, senior executives, ratepayers and shareholders from unnecessary regulatory and financial exposure.
On March 8, 2016, U.S. Bankruptcy Court Judge Shelley C. Chapman permitted Sabine Oil & Gas (“Sabine”) to reject its gathering agreements with two pipeline operators as “executory contracts.” Although the Court’s decision is non-binding as to the underlying issue of the whether the contracts created a property interest in the underlying mineral estate, the ruling could nevertheless create a chilling effect on industry-typical practices regarding such agreements. Prior to this decision, pipeline operators (and the banks providing them financing for building the gathering and processing facilities) have believed that a well-drafted gathering and processing contract for certain minimum delivery obligations would survive a driller’s bankruptcy.
Before filing for bankruptcy, Sabine had entered into gathering contracts with pipeline operators where Sabine agreed to dedicate all oil and gas from certain designated areas, subject to specified minimum volume or payment requirements, to the pipeline operators. The agreements, governed by Texas law, specifically provide that the agreements themselves create a “covenant running with the land.” After filing for Chapter 11 protection in the Southern District of New York, Sabine filed a motion to reject the gathering agreements under the Bankruptcy Code as unduly burdensome “executory contracts.” The pipeline operators objected, arguing that the gathering agreements are covenants that run with the land and, therefore, cannot be rejected in bankruptcy. If the agreements are, in fact, covenants that run with the land, they would not be subject to rejection in bankruptcy.
The legal issue before the Court, then, was whether the gathering agreements are executory contracts subject to rejection in bankruptcy (thus creating a breach of contract and putting the pipeline operators in the category of general unsecured creditors), or if the agreements create a property interest that attaches to the mineral estate and continues with the land, unaffected by the bankruptcy.
The Court did not resolve the property interest issue in its ruling. Rather, the Court decided that Sabine satisfied the “reasonable business judgment” standard that is applied in determining whether executory contracts have been properly accepted or rejected by the debtor. For procedural reasons (the issue was before the Court on a Motion to Reject rather than an adversarial proceeding or contested matter, and the Court found that a substantive legal ruling must occur in the context of one of the latter), the Court explained that it’s decision was non-binding. However, it left no doubt as to what the final, binding determination would be if properly brought before the Court:
If it is ultimately determined that the covenants at issue in the Agreements do not run with the land, as the Debtors and the Court believes to be the case, the Debtors will be free to negotiate new gas gathering agreements with any party, likely obtaining better terms than the existing agreements provide. If, however, the covenants are ultimately determined to run with the land, the Debtors will likely need to pursue alternative arrangements with [the pipeline operators] consistent with the covenants by which the Debtors would be bound. In either scenario, the Debtors’ conclusion that they are better off rejecting the [gathering] Agreements is a reasonable exercise of their business judgment. Therefore, even though, as explained below, the Court’s conclusion that the covenants at issue do not run with the land is non-binding, the Court finds that the Debtors’ decision to reject each of the [gathering] Agreements to be a reasonable exercise of business judgment.
Applying Texas law, the Court noted that “language in a contract containing a covenant is the primary evidence of the parties’ intent, but terminology is not dispositive.” Instead, applying admittedly archaic property law principles, the Court determined that a covenant runs with the land when, among other elements, and it “touches and concerns the land.” The Court also considered whether there was “horizontal privity of estate,” which traditionally involves a property owner reserving, by covenant, an interest in the property for a third party.
Under the Court’s analysis, the primary terms of the gathering agreements relate to the rights and obligations regarding the oil and gas rather than to the land or leasehold interests from which they came. Further, the right to transport and transform the oil and gas products is not one of the property rights of a mineral estate under Texas law. The Court went on to find that to “touch and concern the land,” a covenant must affect the owner’s interest or its use of the land, and the gathering fee covenant had no direct impact on the land or on Sabine’s property rights.
While this ruling may fuel a driller’s desire to re-negotiate more favorable terms with pipeline operators, the impact of the non-binding ruling is still limited to the specific terms of those gathering agreements and the state law governing those agreements.
There are plenty of contract drafting questions to consider in light of the ruling. The Court distinguished certain cases where covenants were found to grant property interests, and arguably drafters could work to more closely mirror those covenants and the underlying provisions to create a genuine property interest.
Another option may be to consider an entirely different drafting approach, such as structuring the gathering agreements as forward contracts and/or swaps, especially in light of the CFTC’s recent willingness to include transportation and tolling agreements in the definition of a swap. Such a designation could potentially bring these contracts under the safe harbor provisions of the Bankruptcy Code, and the parties’ initial intent to have a gathering agreement survive a driller’s bankruptcy could be preserved.
On March 16, 2016, the Commodity Futures Trading Commission (the “CFTC”) adopted a final rule that eliminates reporting and recordkeeping requirements by “end-user” counterparties to trade option transactions. The final rule will become effective upon publication in the Federal Register. The immediate impact of the final rule is that end-users will not have to file Form TO by April 1, 2016, as would have been required by an earlier no-action letter issued by the CFTC. The final rule appears to be mainly good news for commercial energy firms. End-users don’t have to file Form TO and they are relieved from certain recordkeeping requirements for trade options. Further, end-users’ swap reporting counterparties (formed by entering into bilateral swaps with other end-users) are no longer required to report trade options. Also, the CFTC indicated that it will not require trade options to be subject to position limits in the much-anticipated final rule on position limits. Finally, the CFTC removed a requirement to file a notice with its Division of Market Oversight when any market participant’s aggregate notional value of trade options, in a calendar year, reaches $1 billion.
Unfortunately, it took the CFTC over three years to arrive to this point, despite repeated filings by various market participants and organizations that all along argued the very same conclusions the CFTC has reached in this final rule. In the meantime, commercial market participants spent countless hours and resources vetting various physically settled transactions such as tolling agreements, take-or-pay contracts, baseload plus swing load transactions, natural gas peaking transactions, commercial and industrial full requirement agreements, seasonal exchange agreements, asset management agreements, and other similar agreements and transactions, in order to determine whether they had to be designated as trade options. Also, many buyers and sellers who disagreed with their counterparties regarding the appropriate designation of certain transactions, experienced additional burdens on their commercial, risk, compliance, and legal resources. After experiencing unnecessary burdens to comply with trade option evaluation and reporting, market participants will certainly have to spend additional resources to update their relevant policies, procedures, training, and contracts documentation in order to implement the final rule. Hopefully, the regulatory evolution of trade options will be a good teaching moment for both the CFTC and market participants, and each side will listen to the other a little more and talk past each other a little less.
The CFTC pointed out in the final rule that the definition of a trade option is not open to discussion. In other words, trade options are here to stay and the CFTC is using its exemptive authority to remove some of the reporting and recordkeeping requirements for some market participants (end-users) at this time. Swap dealers and major swap participants are still required to report trade options just as they report swaps. In her concurring statement to the final rule, CFTC Commissioner Bowen pointed out that “[t]rade options have been caught in a difficult legal bind. Congress sought to ensure that people could not evade our swaps regulations. It did so by both having a very broad definition of a swap, while also limiting this Commission’s authority to exempt swaps by regulation. Fortunately, however, Congress preserved the Commission’s authority to exempt trade options, which is the authority we are once again using today. Importantly, this exemption provides additional legal certainty that our interpretations cannot. But we cannot overrule the Commodity Exchange Act with regulations and interpretations; we will always be bound by that statute. Therefore, I want to caution anyone tempted to rely on an interpretation to avoid CFTC jurisdiction when it comes to options. I fully recognize the difficulty in distinguishing between different types of physical contracts. If a particular contract or an element of a contract serves an economic purpose similar to an option, I believe the best course of action is to exercise caution and not assume your contract is outside of our jurisdiction based on an interpretation. While it may seem fine for a person using these contracts to hope that the interpretation is not called into question, I believe it would be wise, as a backstop, to make sure it also falls within the trade option exemption.” At the end of the day, legislative action may be needed to either clarify or eliminate the very definition of trade option. While the final rule is an important chapter in the trade option saga, there is no doubt that we are still far from the final chapter.
I am pleased to announce that I have been selected by a renowned international conference provider to conduct a two-day seminar titled “Anti-Manipulation in Energy Market Regulation & Compliance.” The seminar will be held on October 8-9, 2013, at NBC Tower in Chicago. I look forward to conducting this important seminar as part of my law firm’s ongoing efforts to educate market participants about the importance of an ongoing and proactive approach to energy trading compliance.
The seminar will be a comprehensive, in-depth, examination of some current and past developments relevant to anti-manipulation regulation and compliance. In particular, I intend to focus on identifying and preventing manipulative conduct in the energy trading arena. To that end, I plan to examine some recent regulatory and enforcement developments. In particular, I will analyze certain trading and hedging strategies that recently have been identified as potentially manipulative. i plan to examine the risks associated with trading physical and financial positions at same delivery points, anti-disruptive trading practices, uneconomic trading, dynamic hedging, and anti-manipulative conduct under the Dodd-Frank Act.
Also, I plan to offer an overview of the best industry practices and standards for creating and implementing a culture of compliance within an energy marketing organization. Further, I will examine some unique steps that physical energy companies can implement to minimize their exposure to an inadvertent violation of the anti-manipulation rules. In addition, the seminar will identify and offer solutions for the best practices in documentation negotiation and drafting including master trading agreements, confirmations, credit, and collateral and netting agreements.
For more information about the seminar, please click on the following link: