For decades, reserve-based lending (RBL) has been a critical source of capital for the oil and gas industry. However, with global oil prices reaching multi-year lows, inventories swelling to record levels and crude demand at a standstill due to the COVID-19 pandemic, banks that helped fuel the fracking boom are now placing more scrutiny on the creditworthiness of oil and gas producers and the shale reserves held as collateral for loans. As a result, the tightening financial pressure may push small and midsize E&P companies to the brink of restructuring debt and/or contemplate bankruptcy. In fact, some banks are even preparing to become operators of shale assets to avoid losses on loans in the event oil and gas companies do go bankrupt.
In light of these events, Opportune Managing Director Randy Osterberg offers his thoughts below on the overall banking/lending environment, how the current situation may change how banks lend to shale companies in the future and why underlying RBL metrics need to adjust to fit realistic risk-reward exposure for banks and lenders.
What’s the general sentiment like today among regional and major banks who have exposure to oil and gas?
Osterberg: It’s been a rough road for these bankers. They began this exercise back in 2014. They’re now into a sixth year of dealing with more downs than ups. There’ve been a few top lenders involved in this RBL space who originally wanted to work through this difficulty and support the industry. Now, it’s where do you go from here? I feel for the banks as they try and work through these ever-increasing issues. You have to look back over the past six years and truly ask, “Have I made money here?”.
It’s hard to compete in a world where you make 200-300 basis points (bps) above London Inter-Bank Offered Rate (LIBOR) and then take it on the chin for a large syndicated loan loss. For example, if you write off an RBL deal for +/- $10 million at 250 bps – that’s $250,000 per year – a large loss to overcome a write down of $10 million. Unfortunately, that eats into your revenue base for many years to come. I think that’s what banks are dealing with right now, and it’s becoming a huge issue. I’m not confident that you can continue to lend at sub-300 bps and think you’ll make up for putting capital to offset potential future write-downs.
Broadly, how might banking/lending change in the future considering the current oil and gas industry downcycle?
Osterberg: I believe in the next 18 months, private equity, which funds much of the oil and gas activity today, will look to capitulate, the M&A market will return in some form or fashion and order will return to this industry. As we all know, the oil and gas industry will survive. The problem is that, given the history of the difficulties in this space, who truly wants to lend at a risk-return capital as we’ve evidenced before? I’m expecting that our 35+ banks will ultimately move to +/- 20 banks and the banks that remain will look to move the cost above LIBOR to something more in excess of 300 bps. By the terminology of risk-grading and the cost of lending against oil and gas reserves, banks will have to measure against a larger return moving forward relative to the cost in the past (subject to the loan-loss provision of the past several years).
"Banks are now looking at a bid-ask spread that leaves the M&A market trying to find its way."
That all being said, I think the oil and gas market will return to its roots. Instead of flipping assets over a change in leasehold cost from limited drilling, oil and gas companies will need to firmly develop a multi-sectional “floor” plan with greater visibility and context to provide assurance for future development opportunities. These “roots” are what provided companies the basis for extending the field throughout the formation and created a footprint for higher capitalized entities to drill for three to five years to come.
How have RBL metrics changed in today’s oil and gas industry vs. past years?
Osterberg: During most of my career with banks, oil and gas lenders would provide 60% to 65% of a risked PV9% on a company’s proven reserve base. And, this PV9% would include PDP (proved developed producing reserves) at 100%, PDNP (proved developed non-producing reserves) at 75% and PUD (proved undeveloped reserves) at 50%, with not more than +/- 20% in categories outside of PDP. Beyond that, banks would build in a commodity price deck that was 10% or less than the prevailing price deck. In a normal world, you could sell PDP at PV10%-15% and non-producing (defined after proving up the locations) in +/- 2x return (“cushion”). This “cushion” was well below the actual purchase prices of these reserves. However, in this new world order, what exactly is the price?
Banks are now looking at a bid-ask spread that leaves the M&A market trying to find its way. If you’re to arrive at a purchase price, a bank’s formula for determining availability is well below their guidelines because they’re now the only true entity with liquidity within an E&P company. Determining some level of availability beyond the current debt is survival for an E&P company, and, if not, you’ve got to deal with a blow-down scenario and adjust G&A accordingly.
"You can build a strategy that appeals to banks (and more importantly the private equity holders), but it’s a long and slow process without a strong end game at the finish as we see it today."
I believe every bank in this current borrowing base redetermination is looking for the administrative agent/arranger to provide a salient argument for what needs to occur moving forward. Given the cost of holding a company’s asset on their books and the use of resources to manage this relationship, banks have got to “fish or cut bait”.
What can oil and gas companies do to persuade banks to provide them much-needed capital in the form of reserve-based loans amid a depressed energy commodity market?
Osterberg: Some companies have acquired assets in this market that permit them to move down the road. I think public companies have shown where the private companies must go to succeed: quarterly dividends, scrubbed G&A, maintenance capex, selective drilling locations and hold on tight. It’s hard on a smaller E&P company to work all four of these figures and make it work over a longer period. We’ve spoken with numerous companies looking to bid, but they remain subject to the chasm between their “bid” on a minimum return to drive equity returns relative to the “ask” from either existing equity owners and/or debt providers.
You can build a strategy that appeals to banks (and more importantly the private equity holders), but it’s a long and slow process without a strong end game at the finish as we see it today. We all remember that start-to-finish for these companies was three years; you’ve got to build your company to last more than five years and have assets that provide flexibility and liquidity over that span.
What can we expect in terms of changes to how banks might determine the creditworthiness of oil and gas companies seeking to obtain capital? Will they be more reluctant to approve borrowing bases going forward?
Osterberg: As I’ve mentioned before, banks will assess the risk in handling oil and gas credits. As such, they’ll look at loan-loss provisions during the past five years and move that into their return hurdles going forward. Banks will further define their oil and gas strategy around making the peg fit into a smaller hole. This peg will consist of four things:
- Tighter Capital Outlays – Lending against non-PDP assets at a clip of 20% or more, increasing cash flow projections that pay beyond the half-life of the revenue stream, greater detail surrounding basis risk and where the assets are housed and determination of a focused strategy in one basin relative to a non-working interest approach in numerous basins (minerals approach).
- Redefined Covenant Packages – Higher minimum liquidity needs, 3.5x debt-to-EBITDAX with an initial 2.0x or less day one (perhaps tighter covenant levels once a company reaches 3.0x in their coverage) and more limitations regarding additional debt through capital structure.
- Maturity Schedule Reduction – Reduce maturity schedule from four to five years down to three to four years; and
- Increase Overall Hedging Strategy To Match Maturity Schedule - Banks have pushed the limit onto higher creditworthy names to give the client leeway to allow them to handle their business without bank intervention. Assuming the dust settles, and this industry is back to square one, banks will have a place in the capital structure moving forward. The question is how much will they pull back on the front end and how quickly thereafter will the lending parameters moving forward induce banks to push that window open again?
