In January President Biden directed the U.S. Department of the Interior to halt issuing new leases for oil and gas development on federal lands and waters. On Tuesday, the Interior Department announced that it will conduct a sweeping review of federal oil and gas leasing.
The study is predicated on the assumption, as stated by a high-level department official in a Bloomberg article posted to Rigzone, that Americans are not well-served by the existing federal oil and gas leasing program. The news agency also pointed out the study could yield lasting implications for future lease sale conditions such as acreage availability, leasing costs, and environmental requirements.
Losing the ability to acquire leases on federal acreage – onshore and offshore – would influence the growth plans of domestic exploration and production (E&P) companies, particularly those that have traditionally operated largely within those areas. The Permian Basin, which encompasses parts of Texas and New Mexico, offers a case in point that the Federal Reserve Bank of Dallas discusses in a March 4, 2021, written statement. The Dallas Fed pointed out that private landowners and the state own the portion of the Permian in Texas, but federal land makes up one-half of New Mexico’s Permian. Consequently, it noted that a federal leasing ban would shift Permian activity – including employment, tax revenues, and other benefits – from New Mexico to Texas.
How might the loss of access to new federal leases affect smaller E&Ps, which typically employ a narrower geographic focus? Rigzone posed questions on the subject to several informed market observers. Read on for their perspectives.
Rigzone: Would you briefly explain how large E&Ps and smaller operators differ regarding acquiring acreage and securing (and using) drilling permits? In other words, how do their strategies differ?
Clayton Gring, Managing Director, Turnaround & Restructuring Services, AlixPartners: Large E&Ps have been very active on the mergers and acquisitions front recently – major transactions include Chevron (NYSE: CVX) / Noble, Pioneer (NYSE: PXD) / Parsley, ConocoPhillips (NYSE: COP) / Concho – and that sort of activity could continue if commodity prices continue to rise. Smaller E&Ps likely won’t have access to the kind of capital necessary to make large acquisitions; however, there is certainly more capital available to the market than in the recent past. Smaller operators and servicers are looking to take advantage of that availability, especially those with near-term maturities or large debt facilities maturing in the next few years. Ultimately, smaller operators will benefit from extending runway or enhancing liquidity and drilling or producing wells in the current rising commodity price environment.
Tom McNulty, Houston-based Principal and Energy Practice leader with Valuescope, Inc.: Smaller operators rely on their expertise in specific formations. They seek to be more nimble than their bigger competitors and are far less diverse. Large E&P companies spread their risk over broader asset profiles and are far more diversified. This dictates how they go after acreage and permits. Bigger players can use the process to block competitors because they have the capital. Smaller players cannot and target where they want to be. The short answer is that smaller operators, if they are good, are focused only where they know they can compete and do well. Bigger players diversify across a variety of plays and, while they do not want to make mistakes, they can from time to time and still survive.
Fernando Valle, Senior Analyst, Oil and Gas, Bloomberg Intelligence: The process is the same, but the costs are much more significant for a smaller operator than for a major to tie-up capital into permits. That likely gives a long runway for a Conoco versus a small operator.
Rigzone: What options do smaller operators have to stay active, particularly if they’ve focused on federal acreage such as the New Mexico Permian? For instance, would acquiring permits from large E&Ps be a realistic route?
Gring: I’m not sure there will be an appetite by larger E&Ps to off-load federal land permits, especially now that they are in limited supply. Smaller E&Ps that have focused on drilling federal lands could take this opportunity to sell their existing permits and refocus their business in other basins and on private lands. However, smaller E&Ps may not look to make such a bold move, especially if they have a strong enough balance sheet to recapitalize and extend maturities to avoid any potential looming cash crunch.
Valle: There aren’t many options if they don’t have the permits. Acquiring land with permits would be one but doesn’t seem realistic. Their best chance is for a change in policy.
McNulty: Smaller players that are well run will pivot to where they can compete. Hundreds of leases and permits were acquired before the new administration took over; both EOG (NYSE: EOG) and Devon (NYSE: DVN) were very active in late 2020, among others. It is too early to tell if buying and selling has picked up, and it is important to keep in mind that leases often expire undeveloped. This building up of lease and permit inventories last year does not necessarily mean that leases and permits can or will be acquired by smaller players. They need to be able to acquire leases on private land on their own and not hope for bigger players to sell them anything.
Rigzone: What lasting changes, if any, do you foresee in the domestic E&P industry – particularly smaller operators – as a result of the Biden administration’s moratorium of oil and gas leasing on federal land and waters?
James Blatchford, Energy Policy Analyst, Bloomberg Intelligence: Lower commodity prices and other factors have been testing operators of all sizes. Smaller ones with less capital and less flexibility are especially challenged, and if they’re focused on federal lands and waters a moratorium worsens the outlook. It’s likely to result in more bankruptcies and more consolidation.
Valle: To add to James’ answer, it increases the likelihood that we don’t reach the 13 million barrels-a-day peak in U.S. production in the coming years. Offshore activity had been quiet, but areas like the Permian’s New Mexico can hamstring growth. The additional burdens put on pipelines is an additional headwind for the sector. That slack in U.S. production is likely to be picked up by international producers.
Gring: It is difficult to say what the long-term impacts of the moratorium will be. Legislation like this will clearly have a big impact on domestic onshore and offshore production, and it would be surprising if that legislation would reverse course and re-open federal lands after the government completes a more comprehensive review.
McNulty: There will be a continuation of the deal talk around consolidation. There are still too many companies chasing finite target packages. Bigger will be better, and the small ones that survive will be the best run and the least levered. Rather than take a buy offer from big independents or a major, I think smaller operators need to merge with each other to form scaled platforms.
Rigzone: Let’s say you’re the head of a small E&P contemplating the next 12 months. What do you see as your top challenges and opportunities?
Valle: Access to capital remains paramount, but the easing of rates and oil price rally have likely bought smaller players some leeway. If the oil price rally sustains, we could see some pressure on oil services pricing; completion crews (frac spreads) may be the first point of pain, as some of the capacity idled in 2020 won’t make it back and the market would likely be tight at WTI prices above $60-a-barrel for a prolonged period.
John Tully, Managing Director, South Region, SAP North America: If you’re the head of an E&P contemplating the next 12 months, the biggest challenge and opportunity you have is to find ways to improve the efficiency and economics of your business to optimize for the times we’re in. The new administration has different priorities, but it’s not a question of whether the industry will adjust; it always has and always will.
It’s a question of how these E&P companies will leverage technology to increase productivity, reduce operating costs and support their plans to scale up operations, add wells and increase workover activity. For this reason, ERP (enterprise resource planning) has been top of mind for E&P companies that work with SAP as it helps you simplify and automate business processes and integrate your back office – for instance, finance, procurement, supply chain, maintenance – to your new oilfield operations. The right system can help you standardize end-to-end processes and generate a consistent data model that provides true visibility to profit and loss at all times.
This is why SAP is seeing high demand from E&P companies for all-in-one, integrated solutions running in the cloud; they’re proven and simple to install. The cloud is a great equalizer for E&P companies, allowing them to gain access to bundled ERP solutions – with a pay-as-you-go model – that helps these operators become more productive, reduce operating costs, and increase their return on assets.
McNulty: The main challenges are the regulatory environment, the energy transition, and access to capital. Price volatility is to be expected, and all commodity businesses experience significant volatility. However, it can be harder to model what regulatory changes will occur and which ones will not occur. The energy transition is expected to put pressure on the E&P industry, but oil, gas, and natural gas liquids are different and have different end-user markets. Demand for energy continues to increase, particularly in the developing world, so I doubt that that the next 12 months will see that much of a change in terms of supply-demand balance. There are dozens of coal-fired power plants being built across Asia, and this would not have to happen if American LNG were more of an option. It cannot be an option if it is hindered here; hurting the natural gas complex in the U.S. causes more coal to be burned in Asia.
Capital continues to be a challenge, and there is growing pressure for hydrocarbon divestment on the buy side. My debt level, if any, would be based on $32 to $35 WTI oil prices and $2.05 to $2.65 gas prices. Anything above that is gravy – specifically, equity gravy. Debt kills in commodity businesses, and the volatility risk has to be borne by equity investors. I would be modestly levered, if at all, and will focus on the resource plays that I know better than anyone.
The opportunities are there for efficient, well-run E&P companies. The cost side should be rationalized to a large degree by now, after a long, tough stretch for oilfield service companies. And the ESG (environmental, social, and governance) front is both a challenge and an opportunity, because it is a positive NPV (net present value) argument for energy companies and should be a value enhancement. I am certain that energy companies that invest in ESG programs, personnel, and assets will be rewarded by capital providers. The bang for the buck is much bigger, because they are actually in the very supply chain that has the biggest impact on the “E” in ESG.
Gring: If I were running a small E&P, I would see opportunities such as capitalizing on the recovery in commodity pricing and on my newfound or increased access to the credit and equity markets. This market will offer opportunities for producers to lock in longer-term hedges at pricing levels they haven’t seen in quite some time. Even with the uncertainties from the new administration, this would be an opportunity to recapitalize and strengthen my financial positioning in an upward-trending environment. Secondly, this could be an attractive environment to purchase assets. Yes, commodity prices are on the rise, but there is still the uncertainty and potential risk that comes with changes to government regulations in the sector. This could be an opportunity to acquire acreage from others that are looking to capitalize on the sale of their assets in what is now a more attractive pricing environment.
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