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Trump’s response to Harvey, Irma, Maria and Sandy: more subsidies for coal-fired power

Those who wondered how President Trump would make good on his promise to put coal miners back to work now have their answer. On September 28 2017, Secretary of Energy Rick Perry dusted off a rarely used power in the Department of Energy Organization Act 1977 (DOEOA) and sent the Federal Energy Regulatory Commission (FERC) a proposal that it make a rule to “establish just and reasonable rates for wholesale electricity sales”. By this he appears to mean allowing coal-fired (and nuclear) plants to charge higher prices based on their contribution to the resilience of electricity suppliers. (Click here for the text of the Notice of Proposed Rulemaking (NOPR)).

Background

For many, the salient feature of US energy markets over recent years has been the astonishing ability of the unconventional gas industry to produce cheap fuel for power generation that allows new gas-fired plants to out-compete existing coal-fired or nuclear power stations. This new abundance of cheap gas has transformed not just the US, but arguably world energy markets, and along the way it has produced dramatic reductions in US greenhouse gas emissions.

Conventional wisdom recognizes the importance of what are generally thought of as baseload generating plant in markets with increasingly high proportions of (often intermittent) renewable generation, and it has two answers to the question of how to make sure there is enough power when there is a risk that the lights may go out because there is not enough plant on the system that can run regardless of whether the wind is blowing, the sun is shining, or gas supplies have been disrupted as a result of extreme weather events. The first is to let the market function freely and hope that the ability of the most secure generators to supply power in extreme conditions will enable them to charge sufficiently high peak prices (albeit on a very infrequent basis) in the wholesale electricity market to allow them to remain in business. The second is to create a “capacity market” alongside the wholesale power market. The capacity market is then designed so as to ensure that resources that will ensure security of supply are maintained at times when it is threatened, by providing sufficient incentives to sufficiently reliable sources of capacity to remain available to keep the lights on. Rather than just waiting for a chance to charge extremely high prices at a few moments when other generators are unable to satisfy demand, they are paid a regular (but lower) premium for being available “just in case”.

Politicians and politically sensitive regulators, if not free-market purists, tend to prefer the capacity market route, because it helps prevent wholesale prices from rising to what might seem excessive levels, and carries less risk that you will have to wait until the lights have gone out a few times before sufficiently reliable generators will act on the electricity market’s signal that it is worthwhile remaining in the market. As a result, capacity markets have been a feature of the US power industry for a number of years. Although subject to frequent rule-changes, one of their guiding principles, in theory if not always in practice, is to try to maintain a level playing-field between the different potential sources of capacity – which can include not only all forms of generation, but also demand-side response. The NOPR is a radical departure from this technology-neutral approach.

Reliability and resilience

The NOPR follows on from the Department of Energy (DOE) Staff Report to the Secretary on Electricity Markets and Reliability commissioned by Perry earlier this year (downloadable here). One of the conclusions of that report was: “Markets recognize and compensate reliability, and must evolve to continue to compensate reliability, but more work is needed to address resilience.” It drew a distinction between reliability (“the ability of the electric system to supply the aggregate electric power and energy requirements of the electricity customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system components”) and resilience (“the ability to reduce the magnitude and/or duration of disruptive events, [which] depends upon [the ability of infrastructure] to anticipate, absorb, adapt to, and/or rapidly recover from a potentially disruptive event”).

Reliability has sometimes been seen as synonymous with dispatchability – the ability of certain technologies to produce power on demand (as compared to “variable” renewables like wind and solar). Resilience on the other hand has often been seen more in terms of the power system as a whole, and the need to improve the resilience of power transmission and distribution networks in the face of increasingly frequent and more severe extreme weather events has been a major driver of increases in network spending. Whereas some would regard gas-fired, coal-fired and nuclear generation as equally reliable, the report, and the NOPR, shift the focus onto resilience and see that quality in terms of the security of a generator’s fuel supplies. In simple terms, coal-fired and nuclear plants are more likely to carry stocks of fuel than gas-fired plants, which tend not to store reserves of fuel, but rely on pipeline supplies. Interestingly, however, despite the NOPR’s focus on “fuel-secure” plants that can store a 90-day supply of power on-site, such as coal and nuclear, the DOE Staff Report noted that “[m]aintaining onsite fuel resources is one way to improve fuel assurance, but most generation technologies have experienced fuel deliverability challenges in the past.  While coal facilities typically store enough fuel onsite to last for 30 days or more, extreme cold can lead to frozen fuel stockpiles and disruption in train deliveries.”  There appears to be a disconnect between the DOE Staff Report’s conclusions regarding fuel supply challenges for all forms of generation and Secretary Perry’s proposal to promote coal and nuclear plants, specifically, which might lead one to draw the conclusion that the move is more motivated by politics and the negative economic consequences to communities resulting from the loss of the retiring coal and nuclear generators and less by the attributes those resources offer the electric grid.

The proposed rule

The DOE’s proposed rule would require all regional transmission organizations (RTOs) and independent system operators (ISOs) (like MISO) to adopt market rules that would establish a rate applicable to generators able to store a 90-day supply of fuel on-site (i.e. coal and nuclear generators) that ensures that those generators recover their costs and a fair return on equity (the traditional cost-of-service pricing standard in the U.S.).  In short, because coal and nuclear resources have not been able to compete in markets dominated by low-cost natural gas, the DOE is requesting/directing FERC to establish market rules that will pay them more in an attempt to stop the trend of the retirement of coal and nuclear plants.  It is a surprisingly blatant attempt to have FERC, which has traditionally favored technology-neutral market rules, set up rules that subsidize specific technologies in order to prop them up.

New York and Illinois have already started moving toward establishing a credit for nuclear generators as part of their programs to reduce greenhouse gas emissions in their states.  So there may be some support at the state level for nuclear as a cleaner form of power.  States have not been moving toward providing credits or subsidies for coal, however (except, perhaps, for those states whose economies are somewhat reliant on the coal industry), so we would expect to see some significant pushback from state governments as to the subsidy for coal.  Also, to the extent that state programs are creating incentives for renewables to enter the market and FERC is creating incentives for coal and nuclear to stay in the market, ratepayers ultimately end up paying for both, even if both are not needed from an energy standpoint.

If you accept the principle that coal and nuclear need “extra help” beyond what they can obtain from the current capacity market, to support their continued operation, there are of course many different ways that such help could be provided. There are also legitimate policy questions to be considered about the risks that in compensating such generators for the service they can provide in particular circumstances, you end up unnecessarily distorting competition in the wholesale power market as a whole. In short, an alternative approach to the resilience problem would be to continue with efforts to enhance co-ordination between wholesale gas and power markets and the development of gas storage capacity, and to improve interconnection between the US’s different regional power markets.

What next?

In response to the NOPR, FERC staff have put together a list of 30 questions (many of them in several parts) for interested parties to comment on, teasing out both the principles behind the proposal and the potentially tricky details of its implementation (click here for the list). But there is apparently little time for either stakeholders or FERC to ponder all these questions, since the DOE has set forth a very aggressive timeline for this matter.

  • It is directing FERC to take final action in the matter within 60 days, or in the alternative to adopt the DOE’s proposed rule as an Interim Final Rule subject to further change after opportunity for public comment.
  • It states that the comment period will be 45 days or whatever period FERC sets out, if FERC can issue a notice establishing a comment period within 2 business days.
  • The DOE also proposes that any final rule adopted by FERC become effective 30 days after it is issued and would require RTOs to submit a compliance filing proposing their tariff revisions to FERC within 15 days of that date.

This is an extraordinarily accelerated timeline, particularly given the issues at stake and that most RTOs have a lengthy stakeholder process for developing new tariff revisions.  Under the DOEOA, FERC is required to “consider and take final action on any proposal made” by the DOE expeditiously in accordance with reasonable time limits set by the Secretary of Energy.  However, while FERC must act upon the proposal, it has exclusive jurisdiction, and thus complete discretion to accept, reject, or modify the DOE’s proposal.  So FERC could issue an order rejecting the DOE’s proposal but initiating a similar rulemaking effort on a more realistic timeline. FERC issued a notice inviting interested parties to file comments on the DOE proposal by October 23, and reply comments by November 7.

Unsurprisingly, much of the industry is far from happy about all this.  The trade associations have by and large rolled out in opposition to the accelerated timeline.  Within a few days of the NOPR, a joint motion of industry associations was filed proposing a 90 day initial comment period and a 45 day reply comment period by the following industry associations:  The Advanced Energy Economy, American Biogas Council, American Council on Renewable Energy, American Petroleum Institute, American Public Power Association, American Wind Energy Association, Business Council for Sustainable Energy, Electric Power Supply Association, Electricity Consumers Resource Council, Energy Storage Association, Interstate Natural Gas Association of America, National Rural Electric Cooperative Association, Natural Gas Supply Association, and Solar Energy Industries Association. (here)

It is remarkable to see the oil and natural gas associations on the same pleading with the municipal utilities, coops, independent power producers, consumer groups, and renewable energy associations.  Their motion argues that the proposed reforms laid out in the notice of proposed rulemaking would result in one of the most significant changes in decades to the energy industry and would unquestionably have significant ramifications for wholesale markets under FERC’s jurisdiction, and that the time frame allowed is far too short to consider such a significant change.  Answers in support of their motion were also filed by the Transmission Access Policy Study Group, Industrial Energy Consumers of America, National Association of State Utility Consumer Advocates, Northwest & Intermountain Power Producers Coalition, and the American Forest and Paper Association. However, in spite of this unusual amount of industry consensus, FERC has denied the request for an extension of time and is holding fast to its October 23 and November 7 deadlines.

It seems unlikely that FERC will be able to take any substantive action within the time frame set forth by the DOE (unless it rejects the proposal outright).

  • Acting Chairman Chatterjee (Republican) issued a statement in response to the August DOE Staff Report on Electricity Markets and Reliability that FERC would remain focused on the wholesale electric capacity market price formation issues, so there may be some will at FERC to proceed with this rulemaking, but there is likely to be strong state resistance, and as the trade associations point out, it is not going to be an easy matter to figure out how to insert a cost-of-service pricing regime for coal and nuclear resources into otherwise competitive wholesale markets.
  • One of the other Commissioners, Republican Robert Powelson, addressed the issue in a speech he gave this week, reaffirming FERC’s independence from the DOE and promising not to “blow up the markets.” He is quoted as saying “We will not destroy the marketplace.  Markets have worked well and markets need to continue to work well.”
  • The third sitting Commissioner, Democrat Cheryl LaFleur, endorsed Powelson’s comments on Twitter.  FERC staff have indicated that the agency is moving forward with the proposal and will take “appropriate action” within the 60-day timeframe requested by DOE (as noted above “appropriate action” does not necessarily mean “substantive action”).

It remains to be seen whether FERC will seriously entertain the DOE’s proposal, it could very well reject it quickly and go about business as usual, or (more likely) it could open an alternative proceeding to see if capacity and resiliency issues can be addressed through a better vehicle. Secretary Perry has stated that his intent in filing the proposal was to “start a conversation.”  FERC is one of the federal agencies that is typically the least impacted by changing political tides, and we do not expect to see the type of radical change in direction that has been seen in other agencies, such as the DOE, EPA and Interior.  Further, as described above, the commissioners have been telegraphing that they support markets and are unlikely to “blow them up,” but they have generally acknowledged that there have been significant changes in the industry that have put new pressures on the markets that may warrant taking a new look at whether there are attributes that the market is not pricing now that should be priced.  Earlier this year FERC conducted a two-day technical conference on the topic of how FERC’s markets are impacted by state goals (such as increasing reliability and decreasing emissions) and whether FERC markets should remain completely independent of such goals, seek to accommodate them, or seek to accomplish them.  Making predictions in the volatile scene of U.S. politics has become an increasingly dangerous game in recent months, but it seems that the most likely course of action for FERC to take regarding the DOE’s filing will be to wrap it up into the ongoing considerations of the markets and establish a more robust rulemaking to consider whether any and all of the attributes that the DOE and states are seeking to promote should be priced in the markets, most likely through a technology-neutral mechanism.

 

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Trump’s response to Harvey, Irma, Maria and Sandy: more subsidies for coal-fired power

Extractives companies’ human rights records ranked in Benchmark study

Developments continue apace in human rights responsibilities for businesses. We are seeing persistent implementation of new reporting requirements across EU jurisdictions and beyond, judgments of national courts and international tribunals holding corporations to ever stricter account for their responsibilities in this area and UN negotiations continuing for a global treaty imposing binding international law obligations on businesses.  Staying ahead of the field in this area is crucial.

While the responsibilities imposed by the UN Guiding Principles on Business and Human Rights (the UNGPs) are not in themselves legally binding, governments’ expectations that companies will step up in this area have been made clear through National Action Plans, parliamentary enquiries and the introduction of “hard” legal requirements, such as under the Modern Slavery Act in the UK.

Now, the Corporate Human Rights Benchmark (CHRB) has ranked 98 of the largest publicly traded companies globally on 100 human rights indicators, focusing on the Extractives, Agricultural and Apparel industries.  These areas were specifically selected because of the high human rights risks they carry, the extent of previous work on the issue, and global economic significance.  41 Extractives companies featured.

The CHRB is a collaboration between investors and a number of business and human rights NGOs. It has emphasised this is a pilot assessment and welcomes input on the methodology used.  The study was compiled from publicly available information, with the selected companies also having the opportunity to submit information to the CHRB.  Companies were given scores for the measures they are taking across six themes, grounded in the framework of the UNGPs:

  • Governance and policy commitments.
  • Embedding respect and human rights due diligence.
  • Remedies and grievance mechanisms.
  • Performance: Company human rights practices.
  • Performance: Responses to serious allegations.
  • Transparency.

The selected companies were then banded according to their overall percentage score.  The performance-related criteria carried greater weight than the policy-based heads, with “Embedding respect and human rights due diligence” and “Company human rights practices” counting for 25% and 20% respectively.

Results skew significantly to the lower bands

There was a wide spread in the participants’ performance, with a small number of clear leaders emerging. No company scored above the 60-69% band, with only three companies falling within that band.  A further three scored 50-59% and 12 scored 40-49%.  48 companies fell within the 20-29% band.

Of the companies in the top band, two were in the Extractives sector; a further six Extractives companies fell within the 40-49% band; 19 scored 20-29% and five were found to trail at less than 19%.

The generally low scores across the three industries may be explained by the fact that the impact of some businesses’ human rights processes may still be filtering through. We should expect that in future years the authors of the survey will adopt a more stringent approach and subject low-scoring businesses to greater criticism.

Gap between policies and performance

On the whole, companies tended to perform more strongly on policy commitments, high-level governance arrangements and the early stages of due diligence. They performed less well on actions such as tracking responses to risks, assessing the effectiveness of their actions, remedying harms and undertaking specific practices linked to key industry risks.  There is often a mismatch between board level measures and their granular implementation, as well as between public responses to serious allegations and taking appropriate action.

Of the Extractives companies surveyed, only six companies scored were given a zero score for their policy commitments, whereas this was the case for 17 companies for “Embedding respect and human rights due diligence” and nine for “Company human rights practices”.

On the policy side, some Extractives companies scored points for emerging practices such as regular discussion at board level of the company’s human rights commitments, linking at least one board member’s incentives to aspects of the human rights policy, and committing not to interfere with activities of human rights defenders, even where their campaigns target the company.

In terms of implementation, some participants explained how human rights risks are integrated into their broader risk management systems, how they monitored their commitments across their global operations and business relationships, and how they had systems in place for identifying and engaging with those potentially affected by their operations.

Companies were also scored for their practices in relation to selected human rights specific to each industry. Those in which the Extractives participants featured included freedom of association and collective bargaining, health and safety, land acquisition, water and sanitation and the rights of indigenous people.

Conclusion

The significant interest in the CHRB since it began its work is unsurprising given it provides an opportunity to demonstrate commitment and progress in this area vis-à-vis competitors. The pilot methodology will be refined and ultimately the CHRB will be produced on an annual basis for the top 500 companies globally.  We expect it to contribute to the continued drive of companies across all sectors to proactively manage human rights risks in their own operations and through their expectations of their business partners.

Extractives companies’ human rights records ranked in Benchmark study

Suspension of coal leasing

The United States Department of the Interior has announced a temporary suspension of coal leasing on public lands pending a comprehensive review of the federal coal program by the Bureau of Land Management (BLM).  Public lands currently account for approximately 40% of all coal production in the United States.

During the temporary suspension, BLM will not process or approve new coal lease applications.  The suspension does not halt ongoing production activities under existing leases or prohibit the approval of new coal leases on Native American tribal land.

The temporary suspension will impact a number of pending lease applications, and it is already receiving considerable attention in the media and in the Congress.  But the BLM’s comprehensive review of the federal coal program is likely to be even more important in the long run.

The comprehensive review will take the form of a Programmatic Environmental Impact Statement (EIS) prepared under the National Environmental Policy Act (NEPA), a document that will be available for review and comment by interested parties.  Among other things, the Programmatic EIS is likely to address the following questions:

  • How, where, and when should public lands be leased for resource extraction activities?
  • To what extent should coal produced on public land be used to support American energy needs?
  • Should rents and royalty rates charged by the United States account for the “social cost” of carbon?
  • To what extent should government leasing decisions account for the potential environmental impacts of resource exports?
  • How should climate change impacts be addressed in the federal leasing and environmental impact assessment process?

The importance of these questions (and the answers that will emerge in the EIS) extends far beyond federal coal leasing.  All stakeholders with an interest in federal land management and energy policy should take careful note of — and consider directly participating in — the BLM’s Programmatic EIS process.

Dentons’ award-winning Energy, Environment and Natural Resources practices specialize in helping project proponents, industry associations, financial institutions, and other stakeholders successfully navigate the Environmental Impact Assessment process and evaluate the strategic implications of federal agency decision-making.

Suspension of coal leasing

Current trends in oil and gas finance

Leslie Benedict: “Money isn’t everything, Jett”
Jett Rink: “Not when you’ve got it.”
Giant (1956)

And when you don’t got it, as independent oil guy Jett Rink knew, it is everything. The world may run on oil, but the oil industry runs on capital, and for some US shale producers that capital appears to be drying up. After flowing downhill throughout the second half of last year, the price of West Texas Intermediate (WTI) crude oil (as of the date this article is being written) is currently at about US$30. Natural gas has faced a similar decline. Might the worst be over? Not yet. Credit Suisse believes that between 1864 and 2008, the four oil bear markets lasted on average two decades and the shortest 11 years. Expect more pain ahead for many exploration and production (E&P) companies who focus on shale oil, deep water oil, or oil sands (collectively, “unconventional oil”) with additional ramifications in the oil field services sector and other related industry segments.  If commodity prices settle at or near today’s prices, many E&P unconventional oil companies may face a liquidly crises while others will require either in-court or out-of-court restructurings. To date, 48 North American E&P companies have filed for bankruptcy. Six E&P companies have filed bankruptcy so far this year. Oil has had its weakest start in history and has negated five year gains.

The current downturn is a reminder that oil and gas exploration and production has always been a cyclical business. Memories of the last downturn in the sector may have faded but investors should keep in mind some of the unique industry and legal issues involved in oil and gas finance.

Weak global demand and the quest for yield

The immediate cause of the present oil price collapse is found in increasing production and weak demand for all commodities and loans since 2008 despite the herculean efforts of central banks to restart global demand via ultra loose monetary policy.  Since the Financial Crisis of 2008, the US Federal Reserve and central banks across the world have increased debt, artificially kept interest rates low and devalued their currencies.

Oil prices rose with a weak US dollar and interest rates near zero in 2009. As prices passed US$80 per barrel in late 2009, unconventional oil production began in earnest. Low-interest rates forced investors to look for yields better than they could find in the US Treasury bonds or conventional savings instruments. Money flowed to E&P companies through high-yield corporate bonds, loans, joint ventures and share offerings.

The extended period of ultra-loose monetary policy, including both exceptionally low interest rates and huge expansions in the balance sheets of central banks helped produce the highest sustained oil prices in history. They also led to investments that are not particularly productive but promise higher yields that can be found otherwise in a zero-interest rate world.

A US-led supply surge from high-cost unconventional fields such as the Bakken, Eagle Ford and the Permian Basin outstripped demand last year and sent oil prices spiraling downwards. The rout deepened in November 2014 after OPEC, led by Saudi Arabia, its largest producer, refused to cut production. Other sizeable producers, like Russia, are hard pressed economically and need to keep producing for current cash income. And this is before the impact of Iranian oil coming back into the market.

The key to recovery is increased demand. With demand from China dramatically down and the potential for recession in many other sizeable energy consuming markets, the short-term scenario for demand does not look promising.

Continuing technical innovation which increases production from existing fields and new areas can also be a factor going forward, as it has been over the past decade or so. This can further increase supply from one or more regions of the world, often in dramatic fashion and/or at lower cost than some current production techniques.

E&P restructuring drivers

Since the 1970s, oil companies have put up their own reserves as collateral for loans as a way to secure improved lending conditions. E&P companies rely on reserve-based lending (RBL) to fund operations.  In return, banks demand to revalue those reserves every six months, in April and October —a process called “redetermination”.  Under RBL facilities, banks agree to lend up to limits set by the value of the borrower’s proved oil and gas reserves. They then adjust those limits periodically to maintain adequate loan-to-value and cash flow coverage ratios.

During the previous round of redeterminations last autumn, banks cut limits for most customers between 10 and 20 per cent. With oil still languishing at about US$30 a barrel, analysts say that the next round could be just as severe.  As reported recently in the Financial Times, John Shrewsberry, chief financial officer of Wells Fargo, one of the most active lenders in US energy, told an industry conference in Miami that borrowing availability would be about “10 or 20 per cent down” again in the spring. Banks have also been warned by the Office of the Comptroller of the Currency, the federal regulator, to watch out for the risk involved in lending to oil and gas companies, prompting fears that loans could be withdrawn from businesses that would be financially viable if they were given a little more time.

In times of steep declines in commodity prices, most E&P companies will find the availability for additional borrowings under an RBL facility reduced, in some instances to a level below the aggregate principal amount of loans outstanding, resulting in a borrowing base deficiency. Once a borrowing base deficiency has occurred, most RBL facilities will provide the borrower the option to add additional collateral with a value equal to at least the deficiency amount or to pay down the outstanding loans in an aggregate amount equal to the deficiency in a single payment or in equal installments of three to six monthly payments. In a typical RBL financing, substantially all of the collateral has already been pledged to the lenders as collateral, which leaves the borrower only the option of paying down the debt. Choosing to repay the deficiency amount in installments gives the borrower a short window of time to raise capital, including by selling properties or securing additional credit through junior lien or subordinated debt, in order to avoid an event of default under its RBL facility.

Financing alternatives

The cliché about the hydrocarbon business is that the cure for low prices is low prices, meaning that excess production should lead to a mass wave of insolvencies, cutbacks in activity and eventual price recovery for the rational, hardy survivors. But to date, that does not seem to be happening. Relatively strong debt and equity markets (aided by private equity and hedge funds) have allowed many energy companies to access the financing needed to fight another day.

At the corporate level, there are 2nd lien debt (bond or loans) “replacement” revolvers, DIP financings and equity investments. According to Bloomberg, oil companies have sold US$61.5 billion in stocks and bonds since January 2015 as oil prices have tumbled. Approximately half the money has been used to pay down or re-structure debt. According to Bloomberg, drillers in the Permian Basin, the biggest US shale field, have raised at least US$2 billion from share sales over the past eight weeks. And more issuances are on the way as producers try to avoid piling on additional debt. Pioneer Natural Resources Co.’s 12 million-share issuance on Jan. 5 was followed a week later by Diamondback Energy Inc.’s announcement of a four million-share sale. Private equity firm Kayne Anderson Capital Advisors LP is investing in a startup called Invictus Energy LLC with $150 million to drill the Permian and the Eagle Ford Shale.

At the asset level, there are many creative ways to invest in E&P companies, including, production payments, net profit interest, overriding royalty interest and out right purchase of a stake in the working interest. Whether acquired as part of a recent restructuring initiative or historical purchase, investors who own such carved out royalty interests need to take inventory of counterparty risk and how these positions will be treated in a bankruptcy, including the potential risks of contract recharacterization or rejection and clawbacks of payment already received. For instance, when these types of interests are structured correctly, the party advancing the money is treated as a purchaser of the future production. If the borrower fails, the oil and gas subject to the production payment belongs solely to the investor and cannot be borrowed against or sold by the debtor. Other creditors of the borrower have enormous incentive to attack the transaction and have it characterized as a financing rather than a sale of assets. If an attack is successful, an investor may find themselves a creditor potentially holding a large unsecured claim against a debtor as opposed to holding what they thought was a separate property. That claim will be subject to treatment in a plan of reorganization.

Oil and gas restructuring considerations

E&P companies facing excess leverage or insufficient cash flow may pursue restructuring strategies out-of-court and, if necessary, reorganization in court by filing for bankruptcy, most often under Chapter 11 of the United States Bankruptcy Code (Bankruptcy Code). The typical parties in an energy restructuring or reorganization include the company as debtor, management, secured lenders, bondholders, potential asset purchasers, trade vendors, service vendors, oil and gas lessors, contract counterparties under joint operating agreements, derivatives counterparties, co-working interest owners, farmors, farmees, production payment counterparties, first purchasers and equity holders. Additionally, the Bankruptcy Code provides standing under appropriate circumstances for statutory committees of creditors and equity holders, and potentially for appointment of a bankruptcy trustee or examiner.

E&P cases also present some unique legal issues compared to most Chapter 11 cases, including (i) whether the personal property or real property rules apply (which provide for different rights and time periods), (ii) how special state law rights and priorities such as liens and royalties are treated vis-à-vis secured and other creditors, (iii) whether certain production payments are true sales or disguised financings (as highlighted above) and (iv) whether environmental and clean up obligations can be discharged in the bankruptcy and how such claims are classified and treated.

It is important to note that bankruptcy is a tool and not a strategic plan by itself. Among the tools bankruptcy provides are: (i) a breathing space from creditor payment demands and remedies, (ii) the ability to borrow funds or use cash collateral (e.g. cash on hand and incoming receivables and payments) on a post-petition basis to fund its business, (iii) the ability to sell assets to fund operations often on a free and clear basis, (iv) the ability to pay certain claims at a large discount and/ or over time, (v) the ability to bind holdouts and dissenting creditors in certain situations, and (vi) the ability to reject certain burdensome contracts and leases.  Companies that restructure crippling debt loads can often emerge from bankruptcy and start life anew, but with the latest fall in energy prices, even a freshly capitalized balance sheet may not be enough to save the company

Indeed, bankruptcy by itself does not solve problems such as ongoing revenue and pricing issues or the need for going forward capital and trade creditor support. For example, when Samson Resources filed for bankruptcy in September 2015, wiping out US$4.2 billion of equity, the expectation was that second lien lenders, in the middle of the capital structure, would take over the company, wiping out the junior debt but paying senior debt holders 100 cents on the dollar. Now that assumption is being questioned and the pre-filing agreement with creditors has fallen apart. With the drop in energy prices “elements of the restructuring agreement, including refinancing senior debt and a commitment to inject new money, are likely no longer feasible”, according to a court document filed on December 17, 2015, in Delaware. “Any new restructuring would likely provide significantly less value for stakeholders than the transaction (originally) contemplated.” Second lien lenders who expected to take over Samson had pledged to put US$400 million into the company. But with prices of natural gas less than US$1.75 per million British thermal units —when the investment thesis of the original owners required prices of US$4 per mmbtu —“it was rational to take another look”, said one person involved in the talks. In its attempt to survive, Samson has cut costs and suspended all drilling.

Conclusion

Although the immediate cause of the collapse is over-production of tight oil, the key to recovery is a material increase in demand. Worldwide demand for oil has increased—its just that the rate of increase in demand has dramatically slowed down. The problem is structural and firmly rooted in the speculative money that was funding under-performing US unconventional oil companies since 2010. A possible first step to price recovery is the severing of capital supply to E&P companies that could not fund their operations from cash flow when oil prices were more than US$80 per barrel. If this does not happen, the world could be in for a long period of low oil prices. Until then, distressed investors should remain mindful of the inherent benefits and risk of investing in the E&P space as they evaluate opportunities resulting from this downtown.

Current trends in oil and gas finance