Midyear Market Update
Recovery Continues But Uncertainties Remain
Editor’s Note: The world economy runs on oil. But what does oil run on when the world economy shuts down?
Coming up with a collective answer unfortunately came down to individual companies making tough decisions throughout the second quarter. Since March and April, however, both the S&P 500 and the Dow Jones Industrial Average have climbed 40%, and the Dow Jones U.S. Oil & Gas Total Stock Market Index is up 50%. Similarly, oil prices are hovering at $40.
The billion-dollar question is, where does the industry go from here? Forecasts have never contained more “buts,” “contingent upons” or “alternative scenarios.” And for oil and gas producers, an added concern is the availability of capital, which afuels drilling and completion, asset acquisition, and midstream activities.
To get expert perspectives on the state of the oil market and the broader banking and private equity markets that support both the upstream and midstream sectors, AOGR presented questions to Ann-Louise Hittle, vice president, macro oils, at Wood Mackenzie; David Morris, managing director at Opportune LLP; and Jason Downie, co-founder and managing partner of Tailwater Capital.
Questions are in italics, followed by the panelists’ responses.
OIL PRICE RECOVERY
Ann-Louise Hittle is vice president, macro oils, at Wood Mackenzie. With more than 25 years of experience analyzing global oil markets, she leads the company’s macro oils service. Before joining Wood Mackenzie, Hittle served as CERA’s research head of upstream oil service, with responsibility for world oil market analysis. She began her career with Gulf Oil, and then served as staff editor with Petroleum Intelligence Weekly, focused on OPEC and markets in Asia. Hittle is a graduate of St. Lawrence University and holds a master’s in Middle East studies from Harvard University.
Q: Even though 2Q2020 began with unprecedented turmoil in the financial markets, major stock market indices staged a sharp rally to close the quarter. Oil prices followed a similar course, reaching $40 a barrel by the start of 3Q2020. What factors potentially could hasten or hamper the ongoing recovery? Where do you see oil prices going from here?
HITTLE: The crucial factor for the second half of 2020 is the rate of demand recovery. We saw the lowest point for the decline in demand during April, and since then, it has climbed steadily. With China ahead of the rest of the world in its response to the pandemic, it is leading the way in a slow return to growth next year.
Assuming another global economic shutdown on the scale of what we saw in the second quarter of this year is avoided, then we expect continued, gradual recovery throughout 2020 in most oil products, with the exception of jet fuel, which we estimate will take a few years to return to 2019 levels as passengers regain confidence in travel by jet.
With OPEC+ production cuts in place, and demand on a recovery trajectory, we see crude prices reaching an average of $52 a barrel for Brent in 2021.
Q: In mid-April, after OPEC and Russia had reached an agreement to cut production, you stated, “We expect the second half of 2020 to show an implied stock draw, in contrast to the record-breaking oversupply of the first half of 2020.” Do you still foresee a sustained pattern of inventory drawdown over the next six months?
HITTLE: Yes, we do still expect an implied global stock draw for the second half of 2020. Already, world oil demand had gone from a sharp fall of 15 million bbl/d year-on-year during the COVID-related shutdown early in the second quarter to minus 5 MMbbl/d year-on-year by the end of the quarter. That is still a dramatic decline. But it also is 10 MMbbl/d more demand during the quarter. At the same time, OPEC+ producers are aspiring to reduce their output by 9.7 MMbbl/d and U.S. production is also down. U.S. lower-48 crude and condensate production fell 1.4 MMbbl/d from March to June.
Q: In April, with lockdown orders in place across the country, U.S. oil inventories increased by 47 million barrels–the largest monthly increase on record–and continued to climb to an all-time high by the end of May. How quickly might stocks be drawn down to within a normal range?
HITTLE: As high as stocks were this spring, a return of U.S. crude oil inventories to the five-year average likely will not be seen until the second half 2021. Commercial inventories are going to be impacted by crude oil temporarily stored in Strategic Petroleum Reserve sites returning to commercial inventories in the first half of 2021. Overall, the combination of significant rollover in lower-48 production, plus our current tight global market view, leads to a rough return to the five-year inventory average at some time in the second half of 2021.
Q: Global oil supply was outpacing consumption even before the COVID-19 shutdown. Analysts appear to be increasingly confident that the market has swung back into balance, and that demand now is running a little ahead of supply. How do you assess the supply-demand balance? What consuming sectors are leading the recovery?
HITTLE: Yes, demand is outpacing supply as of this quarter, as we expected. Our approach is to forecast supply on a detailed basis by country and demand on a product-by-product and sector basis.
Of the oil products, jet fuel is the laggard for recovery. Much depends on when a workable vaccine is in place, because that will allow a return of consumer confidence for airline passengers. Gasoline and diesel consumption levels are showing recovery, although the rate of economic growth is still a risk since it is contingent on the easing of shutdowns.
Q: With demand risk still present, what is the timeline for U.S. producers to restore the thousands of wells shut in during March and April? What impact will that have on U.S. production trends? Outside the domestic market, what lessons did OPEC+ learn in 2Q2020?
HITTLE: For the United States, we expect that virtually all shut-in and curtailed production will be back on line by late summer. However, with fewer new well completions taking place, total production is expected to return to a pattern of decline by late 3Q and throughout 4Q this year. Rigs are expected to see a gradual recovery starting in the Permian Basin as early as Q4, followed by other tight oil plays in 2021. We do not see production growth for the lower-48 occurring until later in 2021. For 2020, in our forecast, lower-48 output will fall 400,000 bbl/d year-on-year on an average monthly basis.
The OPEC+ group has signaled its clear lesson learned from the price turmoil of March and April. The April 12 production restraint agreement is in place until April 2022, with a meeting planned for each month in order to review market fundamentals. The rate of recovery in oil demand will be the key risk for the group as it meets each month.
David Morris is a managing director at Opportune LLP. Based in Dallas, he has nearly 20 years of experience executing complex financings, negotiating transactions, leading diligence processes and managing legal documentation. Morris previously served as executive director of JPMorgan Chase’s energy finance group. Prior to that, Morris served in corporate banking and debt capital market roles at CapitalOne, KeyBank, GMAC Commercial Mortgage and Progressive Insurance. He holds a B.S. in economics from Duke University and an M.B.A. in analytic finance and accounting from the University of Chicago.
Q: Reserves are the common stock of the oil and gas business. The value of that stock rises and falls with commodity prices, and crucially, directly affects reserves-based borrowing determinations. What do you see ahead for reserves-based lending (RBL) as fall redeterminations approach? How could the dynamics shift should prices continue to edge upward?
MORRIS: Unless oil prices increase considerably more over the next three-four months, more decreases of borrowing bases seem likely in the fall redetermination season despite the oil price recovery since April. While I do not expect significant changes or new developments in bank RBL methodologies for the upcoming redetermination season, I anticipate at least four key themes.
First, many oil and gas companies curtailed or suspended drilling and completion activity in the first and second quarters. As a result of this lower activity, coupled with the natural production decline of producing wells, proved developed producing (PDP) reserves, which receive the highest advance rates or lowest risking in the sizing of an oil and gas RBL, will decrease compared with the just-concluded spring redeterminations. Whether higher oil and gas prices will be enough to offset the present-value impact of lower PDP reserve volumes remains to be seen.
Second, existing and newly booked proved undeveloped (PUD) locations in mid-year reserve reports will face increased scrutiny by banks. Which PUD locations are projected to generate rates of return in excess of the lenders’ hurdle rate thresholds? Are the projected well costs, operating expenses, and production volumes reasonable and supported by historical data? These are only a few of the questions that bank engineers and credit professionals will be considering as they evaluate midyear reserve reports.
Third, banks will carefully evaluate each borrower’s liquidity, expected cash flow, leverage and commodity hedge protection. Does the borrower have enough liquidity to justify borrowing base credit for its PUD reserves?
Finally, some companies may have to trade borrowing base reductions for financial covenant relief from their bank groups, while other less-challenged companies may face pressure from retrenching banks to decrease their borrowing bases. Banks will be especially motivated to reduce exposure to RBLs of companies that are anticipating high leverage (greater than 3.5 times) in 2021.
Q: With operators continuing to face a high degree of business risk, many companies are highly leveraged and would be vulnerable should prices come under renewed pressure. How would you describe the general sentiment among banks with exposure to oil and gas? Could today’s market environment permanently alter the risk/reward metrics for bank RBL programs?
MORRIS: The capital markets have very little appetite for oil and gas equity and debt exposure, and the U.S. market for oil and gas properties remains exceptionally weak. In addition to an oversupply of oil in the first half of 2020, the industry still is suffering from COVID-19-related demand destruction. Many “oily” independent companies had very little of their 2020-21 production hedged prior to the price rout. For these and other reasons, I think the sentiment is negative among the banks engaging in oil and gas RBL. Many may be wondering what OPEC and Russia will do when global demand eventually recovers.
If oil prices increase significantly in the near future and oil production ramps up again in the Permian Basin, will natural gas benchmark prices or basis differentials suffer due to the resulting increase in associated natural gas production? Are there gas-focused companies that are vulnerable to this potential shift?
I am not bold enough to predict permanent changes in the oil and gas business, particularly the financing of it. Eventually, bankers will retire, institutional memories will fade, and oil and gas prices will increase enough to embolden banks and other investors to become more aggressive. However, in the foreseeable future, I would not be surprised to see banks re-evaluate their guidelines for assigning loss given default (LGD) percentages to oil and gas RBL and conclude that LGDs should be higher. Typically, loans with higher LGDs have higher interest rate margins. Indeed, we already have seen loan pricing increases in conjunction with spring redeterminations.
Q: How are banks responding to the financial pressures associated with lower commodity prices, reduced reserves valuations and ratcheted-down borrowing capacities?
MORRIS: Most banks are responding rationally to lower commodity prices and stressed collateral coverages, seeking to restructure loans when doing so yields a materially higher expected recovery than forcing a sale of the collateral properties in the current market. Out-of-court restructurings are possible and will occur. However, if a borrower has junior debt and/or midstream obligations in the capital structure, out-of-court solutions will be more challenging, if not impossible. Whatever the case, I expect the banks to be more active/vocal in all restructuring situations, and not just those where the secured revolver is clearly the fulcrum.
There may be some vulnerable producing companies that struggle to reduce leverage even when oil prices recover if, during this downturn, they lose significant borrowing capacity that otherwise could have been available to fund drilling and completion spending in excess of operating cash flow. In addition to having little borrowing base availability, such a company will have high leverage (total debt to EBITDAX in excess of 3.5), which can make it difficult to raise new/increased commitments from commercial banks even if proved reserves support a borrowing base increase.
If oil prices continue to recover and the global demand outlook improves, I think some of these vulnerable companies, particularly those with good acreage, will attract a lot of interest from investors.
Q: What crucial factors are banks looking at when it comes to deciding whether and how to restructure an operating company’s reserves-based debt? What can oil and gas companies do to enhance their creditworthiness and strengthen their standing with their existing banks?
MORRIS: Banks consider many factors when evaluating options for a distressed borrower, including:
- Is there other debt (second lien, senior unsecured, etc.) in the capital structure?
- Are there any midstream contracts that need to be restructured?
- Does the selling, general and administrative expense burden need to be restructured?
- What is the fulcrum (natural equity owner based on value) in the capital structure?
- Are there existing commodity hedges that should be terminated or restructured? Perhaps the banks will want to maintain some or all of the hedges to underpin the cash flows after the debt is restructured.
- How is the asset quality (location, reserves quality, drilling economics relative to other areas, etc.)? Does the asset base have good drilling economics with modest commodity price recovery, or is it a candidate for a PDP blowdown? How marketable are the assets now and in the future if commodity prices rebound?
- What is its assessment of the management team and the general and administrative resources needed to operate the asset base?
- What are the expected recoveries from restructuring the debt (partial equitization, term-out of some RBL debt, etc.) versus selling the assets versus blowing down the PDP reserves and sweeping the cash flow to repay secured creditors? What are the time frames for each option?
- Are the banks willing to own the assets?
I think the oil and gas companies that are weathering this oil price volatility relatively well provide good examples of what operators can do to bolster their creditworthiness and reassure their banks. In short, those companies maintain strong liquidity, operate with relatively low financial leverage, consistently hedge a meaningful portion of anticipated production, and do not rely on borrowing base availability to fund deficit spending plans.
Q: For those companies with favorable balance sheets, what do you expect in terms of how banks evaluate the creditworthiness and borrowing capacities of operators seeking to obtain reserves-based financing? How might that impact the strategies of companies looking to buy distressed assets in the coming months?
MORRIS: I don’t expect dramatic changes to banks’ underwriting methodologies for oil and gas RBLs. Instead, I think banks will expect and negotiate for better collateral coverage that is primarily reliant on PDP reserves (more mortgage coverage), low debt leverage, prudent liquidity, a minimum equity contribution in the case of acquisitions and some minimum level of commodity hedge protection.
How low leverage needs to be and what constitutes prudent liquidity will be based on the specific oil and gas properties supporting the financing (conventional, unconventional, offshore, etc.) and the borrower’s development plan, among other things.
Aspiring buyers of distressed assets may be surprised by banks’ requirements for higher equity contributions to partially fund acquisitions regardless of the value attributed to the target properties by the banks, as well as minimum hedge protection conditions that may be necessary to support borrowing bases but limit equity investors’ ability to capitalize on near-term upside in commodity prices.
PRIVATE EQUITY PLACEMENTS
Jason Downie co-founded Tailwater Capital in 2013. His primary responsibilities include deal sourcing, execution and monitoring of investments, as well as management of the firm. With 27 years of investment experience, Downie was a partner at HM Capital before co-founding Tailwater. He began his career as an associate responsible for energy and transportation in Donaldson, Lufkin & Jenrette’s equity trading group, and then served as an associate at the mezzanine private equity firm Rice, Sangalis, Toole & Wilson. Downie holds a B.B.A. and an M.B.A. from the University of Texas at Austin.
Q: In late March, as COVID-19 roiled global financial markets and ground business activity to a standstill, Tailwater Capital closed $1.1 billion in institutional capital commitments to Tailwater Energy Fund IV and co-investments. Amid so much uncertainty, and bucking a trend of declining private equity placements in oil and gas, what was the secret to securing such substantial investor support? Were the commitments primarily from new or existing investors?
DOWNIE: It really comes down to the fact we have consistently done what we said we were going to do and have been very disciplined in doing it, and therefore, were rewarded by our investor base. We have been fortunate to have limited partners that have serially reinvested with us over the years, and that includes Energy Fund IV.
One of our commitments to investors is to continue to execute a strategy focused on the midstream sector, where we have expertise and a track record of success. Our goal is to prudently manage balance sheets and rates of return on a risk-adjusted basis. We believe that prudent approach is important to limited partners, because as we are seeing right now, having a levered capital structure can be devastating in a down cycle.
A fundamental part of our business is that we do not underwrite a midstream opportunity unless we have a solid perspective on the underlying rock. Everything we do starts with the rock. Our technical team and dataset keep us dialed in with respect to understanding the geology.
We also have deliberately kept fund sizes consistent. Our portfolio goes beyond the traditional midstream, but the focus is on primarily middle and lower-middle market fixed infrastructure assets with contracted revenue streams. By staying in our niche and sticking to our knitting, every fund we have raised to date has had two or three opportunities already defined at first close. That provides visibility into the portfolio early in the capital raise, unlike with most private equity funds, in which limited partners invest in a “blind pool.”
Q: You have indicated that Tailwater sees some of the most compelling buying opportunities in years on the near-term horizon. As difficult as conditions are, what types of opportunities do you see emerging as industry activity starts to recover? How do you expect capital constraints to factor into the equation?
DOWNIE: “Compelling” has a couple different meanings for us, but they share the common definition of generating high risk-adjusted rates of return. The question is how to accomplish that. Should it be organically through green-field projects or by acquiring cash-flowing assets? The risk profiles are very different. We seek to accomplish high rates of return by deploying capital in lower-risk assets with existing cash flows, but that also provide rates of return similar to green-field projects.
Access to public capital has been meaningfully reduced. When capital access is limited, private equity usually fills the gap. Even before the COVID-19 crisis, we were seeing the start of a cycle in which cash-flowing assets with contracts in place could be bought at favorable valuations. Continued post-COVID capital constraints will only amplify opportunities over the next six-12 months. Those opportunities can take many forms, but if you can buy good assets at today’s valuation levels and capitalize them right, the potential returns on those investments can be significant over the longer term, even if demand is slow to fully recover.
We are optimistic that the unfortunate event of COVID-19 will lead to business rationalizations that needed to happen regardless, and that ultimately will provide a more solid foundation of certainty for the entire oil and gas sector, including the midstream. That would be a healthy long-term outcome for the industry.
Q: Since its inception in 2013, Tailwater’s portfolio has been weighted toward the midstream. How do individual prospective investments differ for Energy Fund IV than for those targeted in Tailwater’s previous three funds? To what degree do you envision Energy Fund IV supporting exploration and production companies?
DOWNIE: U.S. shale plays are entering a manufacturing mode. In any manufacturing business, scale and/or vertical integration are important to becoming a low-cost producer. When the products are hydrocarbons, which do not have much brand or technological differentiation, scale and integration are everything. The onshore U.S. market is undergoing a period of consolidation and rationalization. Energy Fund IV investments will concentrate on midstream infrastructure in the plays that are most competitive in terms of how they stack up to global supply basins.
When I think about gas, it’s hard not to like the Haynesville, and there are still opportunities in the Marcellus/Utica. For oil, the Permian Basin clearly has a long inventory runway and low breakeven costs. We also have been incredibly pleased with how resilient the Bakken has been through the last two downturns. For small and mid-sized producers, the Denver-Julesburg and Powder River basins have very good economics. And I can’t forget about the Eagle Ford.
Tailwater’s E&P Opportunity Funds invest in nonoperated producing wells. It has ownership in close to 800 wells, all on shore. That business exists because shale plays have good rates of return when investing with the right operator. As a middle-market player, we are not out to create a large exploration, drilling and production company, but participating in a large E&P company’s wells is a great outcome for us.
We continue to look outside of the core midstream to participate more in follow-on downstream projects. While under pressure because of COVID-related demand destruction, the petrochemical and refining markets have the capacity to remain very competitive globally because of the huge reserve profile of the U.S. onshore.
Q: Studies by the Interstate Natural Gas Association of America and others suggest that new midstream infrastructure spending has peaked. How do you see build-out opportunities going forward? What role will private equity play in financing the next generation of projects?
DOWNIE: There will continue to be green-field infrastructure projects, although they will tend to be smaller and basin-specific. For example, we recently participated in a transmission line project on the Texas side of the Haynesville/Cotton Valley for Sabine Oil & Gas, which is an independent operator that is majority owned by Osaka Gas Co. The interesting dynamic in shale plays is that there is always a need for additional capital deployment for infield gathering, compression, saltwater disposal and other facilities as acreage is developed. Even though there is a lot of existing infrastructure, there will be a need for new projects.
The other major role for private equity is in rationalizing capacities. We are starting to see a wave of consolidation in both the upstream and midstream as noncore assets are rationalized and operations are consolidated. Private equity historically has been a facilitator of the rationalization process, and we expect Energy Fund IV to play a role in midstream aggregation, which will mutually benefit the upstream side as well.
Q: What makes a management team attractive to Tailwater? What particular factors do you look for in an investment?
DOWNIE: We pride ourselves in creating a culture of alignment, transparency and partnership. The executives in our portfolio companies are not employees; they are partners. Our goal is to support them in making decisions, particularly capital deployment decisions. We are deliberate in committing to only a few teams in a basin to foster an environment where management teams feel confident that Tailwater is aligned with their success and they are freed to execute their business plans. We want our teams collaborating to create value instead of competing against one another.
Creating proprietary deal flow and being a first mover are crucial in the midstream sector. Let’s face it, midstream companies aren’t winning many new technology awards. Value often is created when teams have historical experience in a particular basin or vertical segment, which gives them competitive advantage. To fully leverage that, we try to put an incentive structure in place that is completely aligned with our management partners so we are all pulling the oar in the same direction.
This story came from the print edition of The American Oil & Gas Reporter. For other great articles about exploration, drilling, completions and production, subscribe.