The U.S. natural gas market is experiencing an unprecedented transformation. With the technological advancements in shale exploration, combined with increasing exports of natural gas, natural gas liquids (“NGL”) and liquified natural gas (“LNG”), the volumes of natural gas traded in the physical and financial markets are significantly increasing. LNG expansion is increasing the global participation in the U.S. natural gas markets, including the number of market participants with different financial and operational capabilities. This, in turn, is increasing the importance of properly identifying, quantifying, and managing the legal, regulatory, operational, and financial risk associated with natural gas marketing.
The NAESB master agreement for purchase and sale of natural gas and NGL is the most frequently used umbrella agreement in the natural gas industry. Market participants across the natural gas marketing chain such as natural gas producers, gathering and processing companies, pipelines, power and gas utilities, and various commercial and industrial end users rely on the NAESB to memorialize their purchases, sales, and exchanges of natural gas and NGLs. In order to properly manage exposures using the NAESB master agreement, market participants need to understand the relevant legal, credit, and operational aspects of the natural gas business.
I am pleased to announce that I will be conducting an in-depth and practical analysis of the NAESB master agreement, overview of the most critical special provisions, transaction confirmations, and credit support issues relevant to successfully drafting and negotiating NAESB documentation on October 4-5, 2018 in Houston.
At the request of several attendees at the upcoming ISDA seminar, the seminar agenda has been expanded to include an in-depth look at the mandatory margin requirements for uncleared swaps and its effect on various market participants. Dodd-Frank’s swap margin rule requirements became applicable for “financial end-users” on March 1, 2017. However, there appears to be a considerable amount of confusion among market participants about which type of entities are included in the definition of “financial end-user.” In order to address this issue, the seminar will examine the statutory definition of the term financial end-user and some practical steps that market participants can apply in determining their status under the rule. Also, the seminar will include the differences between the terms “hedging entity” and “financial end-user” due to some uncertainty about the impact of each designation on the margin rule implementation.
Many end-users including energy companies, commodity producers, transporters, and marketers have been receiving numerous self-disclosure letters from swap dealers and major swap participants requesting certain identifying information, even though those end-users may not be considered “financial end-users.” The seminar will examine the scope of the margin rule’s impact on the non-financial end-users and what exactly they are required to comply with under the margin rule. In addition, the practical implementation of any margin rule requirements is very likely to impact the underlying swap documentation including any credit support documentation. The seminar will examine some practical steps that can assist market participants in the most efficient way for amending existing documentation in order to comply with the margin rule.
The margin rule’s requirements are likely to increase the cost of OTC (uncleared) derivatives. One of the most pressing challenges for all market participants is the impact of this increased transactional cost on their hedging ability. All end-users, whether financial or non-financial, may have to re-evaluate the availability of hedging opportunities due to market liquidity fluctuations and the cost fluctuation associated with their particular hedging strategies. The hedging headwinds may also be amplified by the potential for regulatory arbitrage as United States regulators, including the CFTC and the Prudential Regulators (OCC, FRB, FDIC, FCA, and FHFA), are expected to significantly modify the Dodd-Frank rules while the European, Asian, Canadian, and Australian regulators are expected to continue their regulatory requirements unchanged, at least for now. The seminar will examine some practical implications of this regulatory arbitrage.
The seminar agenda can be found at the following link: http://kolobaralaw.com/client_alerts.html
Kolobara Law Firm, LLC will conduct a two-day seminar titled “UNDERSTANDING ISDA® AGREEMENT IN THE EVOLVING REGULATORY ENVIRONMENT” on April 5-6, 2017, in Omaha, Nebraska. The seminar is intended to help attendees better understand the key provisions of the ISDA® Master Agreement, Credit Support Annex and various Schedules. In addition, attendees will learn the most relevant and recent regulatory developments regarding mandatory margin requirements, position limits, collateral management, and reporting requirements. This seminar will be a hands-on, practical review and analysis of the architecture of ISDA® documentation, including the 1992 and 2002 Master Agreements, 1994 Credit Support Annex, and Schedules to the master agreement and credit support annex, natural gas and power annex, crude oil annex, long form confirmation.
DAY ONE: APRIL 5, 2017
8:00 AM Registration and Continental Breakfast
8:30 AM The 1992 ISDA® Master Agreement:
- Section-by-section review and analysis of the 1992 ISDA® Master Agreement
- Review of key differences between the 1992 and 2002 ISDA® Master Agreements
10:00 AM Morning Break
10:15 AM Schedule to the 1992 and 2002 ISDA® Master Agreement
- Review of adequate assurances provisions in the ISDA® Schedule
- Examination of relevant calculation agent issues
- Identifying the relevant bankruptcy code representations in the ISDA® Schedule
- The pros and cons of cross-product and cross-affiliate netting and setoff
- Damages and close-out methodologies
- Events of Default and Termination Events
- Counterparty default management
- Set-Off provision
- Interest rate provisions
11:45 Noon Lunch
1:00 PM ISDA® Protocols and Annexes
- August 2012 and March 2013 ISDA® Dodd-Frank Protocols
- EMIR Protocol requirements for the U.S. companies
- Margin Protocol
- Mandatory reporting requirements obligations for end-users
2:30 PM Afternoon Break
2:45 PM Using ISDA® Master Agreement for Physical Commodity Transactions
- Oil Annex
- Power Annex
- Gas Annex
- Bridge Agreement
4: 15 PM End of Day One Session
DAY TWO: APRIL 6, 2017
8:00 AM Continental Breakfast
8:30 AM 1994 ISDA® Credit Support Annex
- Section-by-section review and analysis of 1994 ISDA® Credit Support Annex
10:00 AM Morning Break
10:15 AM Paragraph 13 to Credit Support Annex
- Relevant issues when negotiating exposure thresholds
- Parent guarantees considerations in derivatives transactions
- Letters of credit as collateral for derivatives transactions
- Margin calculation procedures
- Collateral management for derivatives transactions
1:00 PM Review of Supporting Documentation for ISDA® Master Agreement
- Board resolutions and incumbency certificates
- Risk management and trading policies and procedures for derivatives transactions
- Review of recent regulatory development impacting ISDA® agreement
2:30 PM Afternoon Break
2:45 PM Negotiation Strategies for Over the Counter derivatives
- Managing counterparty and operational risk in derivatives transactions
- Memorializing derivatives transactions with long-form confirmations
- Questions and answers
4:15 PM Closing Remarks
Agenda is subject to change.
REGISTRATION FEE – $ 1,599.00
We suggest registering at least two weeks in advance to ensure your seat.
Seminar will be held at the Scott Conference Center located at 6450 Pine St., Omaha, NE 68106 (www.scottcenter.com).
For more information about this seminar please contact Kolobara Law Firm at email@example.com or call 402-881-3987.
The consequences of the 2016 presidential election are likely to have a profound impact on over-the-counter derivatives markets. In particular, the expected changes to the Wall Street Reform and Consumer Protection Act (“Dodd-Frank”)—if not an outright repeal—could significantly impact a wide range of industries and customers globally. Title VII of Dodd-Frank was intended to ensure transparency and accountability to swaps markets. Over the past six and a half years, all market participants, including end-users, swap dealers, and major swap participants, spent billions of dollars implementing the Dodd-Frank statutory requirements, as detailed and enforced by the Commodity Futures Trading Commission (“CFTC”). Some of the Dodd-Frank requirements, such as mandatory margin implementation, position limits, cross-border swap application, and other rules are yet to be finalized.
One of the many major flaws of Dodd-Frank is the failure to exempt from its scope a large number of commercial activities that had nothing to do with the financial crisis of 2008-2009 and that already had a robust risk management history and infrastructure. One such commercial activity is the production and transport of energy commodities. If anything, the financial crisis of 2008-2009 demonstrated the energy industry’s ability to safely and calmly navigate the worst financial landscape. However, the energy industry, among many other industries, was forced to implement numerous Dodd-Frank regulation and to spend enormous sums of money to comply with many regulatory requirements that were misplaced and often overreaching. For example, when an energy company needs to borrow money to build its asset – a pipeline, an electric generation facility, or a crude oil storage tank—it often needs to lock-in a favorable interest rate for its financing. Then, the energy company enters into a plan vanilla fix-for-float swap agreement with an investment bank, i.e., a swap dealer. However, before the swap can be executed, the swap dealer usually sends over a long list of documentation requirements, as it is required to do by Dodd-Frank (or its European equivalent—“EMIR”), to the energy company, including a board resolution authorizing the exemption from swap clearing, a set of policies and procedures “reasonably drafted” to ensure that the energy company’s employees are sufficiently familiar with swaps, various ISDA protocols, margin rule representation letter, EMIR representation letter, and the list of “corporate events” and “life cycle” events the energy company, as an “end-user” under Dodd-Frank must communicate to the swap dealer in order for swap dealer to comply with its reporting requirements.
The nature of Dodd-Frank compliance requirements is very burdensome for most commercial market participants such as energy and agricultural commodities producers, transporters, and marketers, small and medium size banks, insurers, dealers and brokers, because most of them only use swaps occasionally to hedge their commercial operations and, consequently, do not have a robust risk management structure. End-users of swaps do not represent a systemic risk to the U.S. financial system, and the enormous amounts of resources spent on Dodd-Frank implementation only increases the financial burden of the commercial end-users’ customers as those costs are passed down the market chain. However, it does not appear that the CFTC differentiates between those market participants that could jeopardize the global financial system on one hand, and those commercial market participants that only use occasional swaps to manage price risk of their commercial enterprise on the other. In the rush to expand the jurisdiction and assume oversight of all commodities and derivatives, the CFTC appears to have overlooked the need to propose a measured and systemic approach toward a reasonable regulation. The best example of this rush to regulate was the re-labelling of dozens of swap products as futures. The CFTC renamed many swaps and began calling them futures, obliging market participants to trade those products on an organized exchange (and pay exchange fees) and to clear those products on the exchange (and pay clearing fees). While this name change may have been the easiest way to force market participants to trade on organized exchanges, the market participants were left with a complex and expensive task of restructuring their trading, hedging, credit and collateral processes in order to minimize the operational and financial impact of the short-sighted rulemaking. Many natural gas companies are still baffled by the CFTC’s decision that certain natural gas transport contracts could be swaps. The fact that the principal regulator of all commodities markets would label a service contract (natural gas transport) that can only be settled by physical flow of natural gas and called it a swap only demonstrates a lack of basic understanding of energy business. It begs the question, if a regulator does not have a basic understanding of the business it regulates, should such a regulator even continue regulating that business?
As the new U.S. administration forms its strategic vision for financial regulation, many market participants are anxiously awaiting to hear what will become of Dodd-Frank. While a wholesale repeal of the statute seems unlikely because it would create a regulatory vacuum and operational uncertainty, it is clear that many provisions of the statute are unreasonably burdensome. The most likely approach to rolling back Dodd-Frank would be to start eliminating those regulations that burden commercial market participants, especially those that only use swaps to manage their price risk exposure. Also, the regulation of liquidity providers such as dealers, investment banks, and brokers should not be so cost-prohibitive to force such liquidity providers to withdraw from the markets and, thereby, make it more difficult for commercial market participants to find a readily available hedging providers. Any path to rolling back Dodd-Frank is going to take a while because the devil will be in details. For example, the pending final rules on position limits and mandatory margin requirements, just to name two, are much better left to the underlying trading exchanges to manage because the exchanges have the historical data and technical resources to properly monitor and manage them. A margin requirement for bilateral, noncleared, swaps should be left to the counterparties to manage. Most of those bilateral swaps already include some kind of credit support document with margin thresholds. However, each market participant’s creditworthiness should be considered on a case-by-case basis and the best way to do that is at the time of a transaction, in the context of such a transaction and not by a Federal regulator. If the energy market participants had the necessary risk management and business acumen to safely navigate the financial crisis of 2008-2009, they can certainly continue to do so now without the need for the CFTC to hold their hand.
Since some Dodd-Frank final rules are still being finalized, six and a half years after the statute was enacted, any rolling back of the statute is also likely to take several years. What is important during this process is to ensure legal certainty and enforceability of swap and commodity transactions. Also, while it is uncertain where will Dodd-Frank end up, it may be helpful to remind ourselves how Dodd-Frank came about. The primary reason for creating Dodd-Frank was the notion that financial products such as credit default swaps created financial crisis because they were not regulated. The truth was much more simple but, politically uncomfortable–the financial crisis of 2008-2009 was created because some market participants using credit default swaps, mortgage backed securities, and other financial instruments acted irresponsibly, disregarded the most basic risk management principles and common sense. There were plenty of state and Federal statute on the books at the time to punish anyone who engaged in fraud, deception, market manipulation, and similar conduct. However, that would have created some uncomfortable choices for many regulators, prosecutors, and lawmakers. A more convenient approach was to declare that the swaps and other financial products went out of control and caused the financial crisis because they were not regulated. Therefore, a major statute with global impact was enacted, in a large part, based on a false premise. Let’s hope that its replacement will be based in reality and truth.
In recent years, participants in over-the-counter (“OTC”) derivatives markets have experienced an unprecedented regulatory burden. Because of Dodd-Frank, EMIR and similar regulations, the documentation for OTC derivatives is becoming increasingly complex and risky. Many companies are uncertain about their ability to hedge due to regulatory and financial risk associated with derivatives documentation. In order to facilitate an in-depth analysis of the OTC documentation drafting, analysis, and review, I will be conducting a two-day ISDA® seminar on April 5-6, 2017, in Omaha, NE
This seminar is intended to help attendees better understand the key provisions of the ISDA® Master Agreement, Credit Support Annex and various Schedules. In addition, attendees will learn the most relevant and recent regulatory developments regarding mandatory margin requirements, position limits, collateral management, and reporting requirements.
Some of the topics to be covered during this seminar will be:
- Architecture of ISDA® Documentation
- 1992 and 2002 Master Agreements
- 1994 Credit Support Annex
- Schedules to the master agreement and credit support annex, natural gas and power annex, crude oil annex, long form confirmation.
- Various confirmation provisions for interest rate, credit default, and FX swaps.
- Comprehensive overview of events of defaults, remedies, cross-affiliate and cross-products netting and setoff.
- Bankruptcy and liquidation considerations.
- Special considerations regarding swap reporting and recordkeeping under Dodd-Frank.
- ISDA® August 2012 and March 2013 Dodd-Frank Protocols.
- EMIR provisions applicabe to the U.S. market participants.
For more information about this seminar please contact Kolobara Law Firm by email at firstname.lastname@example.org or by phone at 402-881-3987.
Watching the events and the court case surrounding the Standing Rock Sioux Tribe, I appreciate that people are paying attention to any negative environmental impact an oil pipeline may have. At the same time, I cringe at the coverage and the absence of important factual information related to the pipeline’s legal permitting process. When I hear celebrities on the news claim the Dakota Access Pipeline is going through the heart of the Standing Rock Sioux Tribe’s land, I expect the reporters to correct them. The media should tell us that the pipeline follows existing utility easements (including the existing gas pipeline) and runs within half a mile of the tribal land, but does not cross it. No one wants any water to be in danger of contamination or sacred grounds to be destroyed. Because of the pipeline’s location near the Tribe’s land, and a planned route under a lake (again, following the same route as other pipelines, but here, going deeper and with double walls for extra protection), special attention is warranted. And a Federal Court, in response to an injunction filed by the Standing Rock Sioux Tribe, issued a painstakingly thoughtful, 58-page opinion that demonstrated it was fully “aware of the indignities visited upon the Tribe over the last centuries,” and “scrutinize[d] the permitting process with particular care.” See, Memorandum Opinion issued by the Honorable James E. Boasberg, U.S. Dist. Ct. Judge for the District of Columbia, in Standing Rock Sioux Tribe v. U.S. Army Corps of Engineers, Civil Action No. 16-1534, dated September 9, 2016, at p. 58.
The Standing Rock Sioux Tribe sued the United States Army Corps of Engineers to block the operation of the Corps permit process for the Dakota Access Pipeline (DAPL). Thereafter, the Tribe filed a motion for preliminary injunction alleging that the Corps flouted its duty to engage in trial consultations under the National Historic Preservation Act (NHPA) and that irreparable harm would ensue. In its ruling, the Court concluded that the Corps likely complied with the NHPA and the Tribe had not shown it would suffer injury that would be prevented by any injunction the Court could issue. See Memorandum Opinion at p.1-2.
To be clear, the Tribe did not file an action against the pipeline, nor did it seek an injunction against the Corps to halt the permitting process and protect itself from any potential environmental harms. Even though the media’s spotlight on this case is on water, the Tribe has not shown that the pipeline work is likely to cause damage. See Memorandum Opinion at p. 56. In fact, the area around the pipeline’s route has been subject to previous surveying for other utility projects. The pipeline “will run parallel, at a distance of 22 to 300 feet, to an already-existing natural gas pipeline under the lake. Dakota Access will also use the less-invasive HDD [Horizontal Directional Drilling] method to run the pipeline, which will require less disturbance to the land around the drilling and bury the pipeline at a depth that is unlikely to damage cultural resources.” Memorandum Opinion at p. 57 [citations omitted].
With respect to the Tribe’s claim that they had not been sufficiently consulted during the permitting process, the Court outlined the extensive efforts of the Corps—with little success—to consult with the Tribe beginning in September, 2014. Memorandum Opinion at p. 16. In addition to numerous attempts to schedule meetings, the record reflects many letters went unanswered despite extensions in the deadlines to respond, and meetings that were scheduled but later cancelled by the Tribe. See Memorandum Opinion at pp. 16-21. Although there appears to have been some sporadic meetings in 2015, the facts of the case demonstrate ongoing, often ignored, efforts to meet with representatives from the Tribe. Throughout this time, the Corps also invited the Tribe to a general tribal meeting in Sioux Falls set for December, 2015. While five other tribes attended, Standing Rock did not. Memorandum Opinion at pp. 24-25. Meetings did occur in earnest in 2016, with no fewer than seven between the Tribe and the Corps between January and May. In one significant meeting, the Tribe’s archaeologist met with the Corps to express specific concerns about tribal burial sites, and in response, the Corps verified the information and successfully instructed Dakota Access to move the pipeline to avoid them. Memorandum Opinion at p. 28. This fact seemed to carry particular weight with the Court, because it demonstrated the willingness to work with the Tribe and Dakota Access Pipeline’s ready acceptance to re-route where the Tribe raised specific concerns.
In fact, the Court’s extensive opinion outlines the early efforts by Dakota Access to plot its route based on past cultural surveys and then extensive, new surveys to identify potential cultural resources: “[b]y the time the company finally settled on a construction path, then, the pipeline route had been modified 140 times in North Dakota alone to avoid potential cultural resources.” Memorandum Opinion at pp. 13-14. Additionally, the records reflect that where other tribes raised concerns over the pipeline route, Dakota access responded. For instance, when a site was declared eligible for listing on the National Registry that had not previously been identified, Dakota access agreed to bury the pipeline 111 feet below the site to avoid disturbing it. Memorandum Opinion at p. 29. According to the Court, “Standing Rock took a different tack. The Tribe declined to participate in the surveys because of their limited scope. Instead, it urged the Corps to redefine the area of potential effect to include the entire pipeline and asserted that it would send no experts to help identify cultural resources until this occurred.” Memorandum Opinion at p. 29 [citations omitted].
That is why, in response to the Tribe’s claim that the Corps failed to offer it a reasonable opportunity to participate in the Section 106 process (the portion of the NHPA that requires a federal agency to consider the effects of its undertakings on property of historical significance, including property of cultural or religious significance to tribes), the Court said that the factual record of the case told a different story. Summarizing the events, the Court explained that the “Tribe largely refused to engage in consultations. It chose instead to hold out for more—namely, the chance to conduct its own cultural surveys over the entire length of the pipeline.” Memorandum Opinion at p. 48. The Corps contended, and the Court agreed, that it did not have jurisdiction over the entire pipeline, but only discrete areas involving certain waterways.
Overall, the impression left by the Tribe’s legal action appeared to be less about a desire to re-route the pipeline, but instead its intent to stop, and probably remove, the entire pipeline. The Court hinted at this in its opinion, and even pointedly noted that the “relief sought cannot stop the construction of DAPL on private lands, which are not subject to any federal law,” and which comprise of 99% of the pipeline’s route. Memorandum Opinion at p. 51, and at p. 2. It is worth noting, again, that the Court was not without sympathy: “[t]he tragic history of the Great Sioux Nation’s repeated dispossessions at the hands of a hungry and expanding early America is well known. The threat that new injury will compound old necessarily compels great caution and respect from this Court in considering the Tribe’s plea for intervention.” Memorandum Opinion at pp. 50-51.
The Court’s tedious review of the record and careful consideration of the law honored its promised diligence. Despite its heightened scrutiny of the motion before it, the Court ultimately found in that the Corps complied with its permitting obligations, and the Tribe had not shown it would suffer irreparable harm that could be prevented by any injunction the Court could issue.
On the same day the Court issued its ruling that the Corps did everything right, President Obama’s administration (through the Departments of Justice, Army, and Interior) issued a statement that they wanted the pipeline to halt anyway, to see if the Corps needed to reconsider any of its previous decisions regarding the environmental impact of the pipeline. I found this to be a surprising development—on the day the Corps won, it issued a statement that it would nevertheless re-evaluate its permitting, and asked Dakota Access to voluntarily halt construction. By all appearances, it would seem someone or some department above the Corps wanted to deflect the negative publicity, even when the Court ruled the Corps acted properly in granting the pipeline permits.
Then, amidst inaccurate reporting about the pipeline “going through the heart of” the Tribe’s land or through sacred land, the Corps denied the final easement in the pipeline’s construction after initially saying it should be granted. The chilling result is that companies building infrastructure can be faced with so much uncertainty. It is difficult concept to swallow that energy companies should be faced with a moving target—this pipeline is over 90% built—and only 3% of the entire route required any Federal approval.
I do not ignore the important social issues at stake. For instance, maybe the current framework is flawed for engaging a tribe and ensuring meaningful tribal input. If so, we should demand new legislation and ask Congress to change that framework. Nevertheless, even if the current framework is flawed, the facts of the case show that the Corps documented dozens of attempts it made to consult with the Standing Rock Sioux from the fall of 2014 through the spring of 2016 on the permitted pipeline activities, including at least three site visits to the Lake Oahe crossing. See Memorandum Opinion at pp. 14-33. I would encourage anyone who is skeptical of the permitting process, to read the opinion. Lost within the sensationalism surrounding the Standing Rock case, is the chilling message being sent to energy companies who attempt to build our energy infrastructure. Also, I don’t think we should look the other way when the Executive branch of government changes the rules at the end of the game. I don’t think we will like the place such a path will take us.
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.