Capital Providers Offer Range Of Options For Oil And Gas Financing
Editor’s Note: The capital markets supporting the oil and gas industry have been reshaped and realigned in recent years. But in some respects, the more things change, the more they stay the same. With higher commodity prices and renewed borrowing base redeterminations, operators are evaluating all types of opportunities as they balance investment activity with generating returns and maintaining operational discipline–including traditional bank debt, creative finance structures, and property acquisitions and divestitures.
Producers are rekindling relationships with finance providers as they seek to capitalize their 2022 operating programs and build a foundation for solid future business performance. To help them achieve their goals, companies also are looking for the right producing properties in a marketplace that has buyers and sellers finding plenty of common ground.
What capital sources are operators relying on to supplement the industry’s strong cash flows? How are they partnering with banks and alternative capital lenders to meet their long-term business objectives? What are the expectations for A&D activity in the coming months?
To find out, AOGR presented a series of questions to Jason Reimbold, managing director of energy investment banking at BOK Financial; Stuart Rexrode, president and managing partner at BlueRock Energy Partners; and Rene McKale, director of Energy Advisors Group.
Questions are in italics, followed by the panelists’ responses.
Oil And Gas Banking
Managing Director of Energy Investment Banking | BOK Financial
Q: Following an incredibly challenging period during which borrowing bases dramatically shrunk for operators, borrowing base determinations have improved markedly with rising commodity prices. What does that imply for bank lending activity levels in 2022? Do you anticipate continued improvement in borrowing bases in Q1?
REIMBOLD: We can expect lending activity to grow should we see continued improvement in commodity prices. For now, market indicators seem supportive of the current oil and gas prices throughout 1Q22, but as commodity prices fluctuate, we would expect borrowing bases to move in tandem with pricing. Energy is a commodity-based industry, and while it is difficult to predict the future prices for oil and natural gas, we can be confident that pricing will remain volatile.
Fortunately, the industry can utilize hedging as a tool to help manage the risk around pricing volatility, and this is what many of our most successful clients are doing to achieve more even cash flows going forward.
Q: What kinds of financing terms and structures are banks preferring? Has the experience of 2020 left any permanent changes to bank lending structures or risk tolerances for independent oil and gas companies?
REIMBOLD: The events of 2020 led to many changes in our industry, especially in regard to banking this sector. Perhaps one of the biggest impacts on how the industry is banked has to do with the shrinking number of financial institutions that are still willing to be a partner to the sector. Many banks that made oil and gas loans, or participated in other industry-related financings in the past, have elected to exit the oil and gas sector altogether. We saw some institutions withdraw immediately by selling off portfolios of oil and gas loans at a significant discounts, but others are taking a more measured approach to exit by not engaging in new business opportunities while winding down existing portfolios more slowly.
With fewer banks participating in oil and gas financing activities, the industry is experiencing some capital constraints, but this has provided increased opportunities for banks that are committed to the space. While we have seen some more conservative terms with respect to leverage ratios and advance rates in 2021, the basic lending structure has not changed very much. Moreover, higher commodity prices and more active M&A/A&D markets have resulted in many loans getting paid down or paid off. We anticipate a more competitive energy banking market, which should help loosen credit terms.
Q: The activity recovery has been led by private independents, many of them small companies. How are these firms in particular leveraging bank lending? In what ways are they deploying bank borrowings in their operations to supplement cash flow?
REIMBOLD: Smaller private companies were a very active segment of the buyer universe in 2021. Many larger companies have taken advantage of the higher-price environment to shed noncore assets, and this has provided the opportunity for smaller companies to grow their portfolios. Not surprisingly, many of these buyers have utilized bank debt to finance acquisitions.
Often, these smaller transactions are more straightforward from a financing perspective, and with supportive commodity prices, buyers have not had much difficulty securing senior debt to make acquisitions. Otherwise, we are seeing companies maintain strong capital discipline by funding operations primarily out of cash flow.
Q: What do you foresee in 2022 for continued M&A activity? Will asset A&D make a comeback? How can bank debt be used to capitalize on asset acquisition opportunities in the current market environment?
REIMBOLD: While we may see some continued consolidation within the industry via corporate mergers, we do expect increasing A&D activity. The recovery in oil prices has helped to fuel the growing number of asset sales, but the dramatic improvement in natural gas prices has helped to accelerate A&D activity even further. Largely because of pricing, gas-weighted properties have been out of favor for many buyers in recent years, but the significantly improved price for natural gas has heightened the market’s appetite for gas-producing assets. Accordingly, the increasing transaction activity provides for more financing opportunities, and we expect traditional senior debt to remain a significant component for financing acquisitions.
Q: Finally, what trends (both within the industry and outside of it) will drive bank lending in 2022? What do you expect for overall bank financing terms? Will interest rates climb higher? Are banks requiring operators to hedge a percentage of production as part of lending terms?
REIMBOLD: We are expecting client acquisitions to be an important driver of loan growth going forward, and additional opportunities to grow loan portfolios will stem from new market share coming available by some financial institutions leaving the oil and gas sector. It is difficult to say where interest rates will go, but it is unlikely we will see any significant change to financing structures, at least with respect to senior debt. As we move through the cycle, we can expect at times to see a tightening, or loosening, of credit terms as changing market conditions may warrant, but the use of hedging in addition to other risk mitigation strategies should help provide for a supportive business environment in any event.
President and Managing Partner | BlueRock Energy Partners
Q: Do you expect private companies to continue to lead the way in increased drilling and development activity? How do you see factors both internal and external to upstream oil and gas shaping financing trends in 2022, particularly for smaller privates? What role is unitranche financing (combined senior and subordinated debt) playing in giving small independents access to capital to sustain their activity levels and capitalize on today’s market fundamentals?
REXRODE: I do, for at least the first quarter of 2022. Because the publics are still under pressure to return cash to shareholders and prove fiscal discipline, I think it will take a few more quarters before we see significant development activity from that group. The privates are nimbler and more motivated to simply take advantage of higher commodity prices without the added pressure from public shareholders.
I believe this development activity will be funded with private senior debt and mid-risk capital, given the continued pullback in the commercial banking segment and muted public equity markets. Clearly, risk capital, perhaps mezzanine funding, will play a large role in the small independent segment. However, I would emphasize alternative credit versus mezzanine as the key phrase.
With the pullback in reserves-based lending, I believe higher-cost private senior debt and unitranche structures (versus traditional mezzanine) will fill the gap for development capital, as lenders continue to need a high percentage of proved, developed and producing reserves. In the past, mezzanine capital may not have included meaningful PDP production, and many mezzanine shops got burned in the downturn. I believe that profile has changed dramatically. Also, I believe most structures will have amortizing features that coincide with the decline profile of assets being financed. While BlueRock often gets tagged with a mezzanine descriptor, we actually are a unitranche capital provider.
Q: A&D dealmaking rebounded sharply in the second half of 2021 as the industry upcycle gained momentum. How can operators leverage nonrecourse financing to acquire assets? What are the benefits of using nonrecourse structures versus other forms of financing property acquisitions? What type and size of A&D deal is most suitable?
REXRODE: Clearly, nonrecourse capital options are available to operators whereby advance rates against asset purchase price can be significant, sometimes greater than 90%, depending on price against reasonable PDP value. That is especially true if there are attractive development opportunities associated with the asset.
Having said that, the cost of capital will certainly be higher than traditional bank lending, but the required “skin in the game” equity will be reduced. Usually, nonrecourse finance is completely ring-fenced against the specific asset with little to no guarantees and financial covenants. Again, the fewer hooks into other assets brings higher cost of capital, but the flexibility often is the difference in getting the deal closed.
An 8%-12% cost of capital can make a lot of sense when buying PDP assets for PV12-PV20, with upside available. Nonrecourse financing can work in many situations. However, amortizing structures that mirror the decline curve of the assets, whether conventional or unconventional, are most effective because they best ensure the capital provider is capturing cash flow from the specific asset being financed, as opposed to relying on other assets. Assets in the $5 million-$50 million range work well with nonrecourse structures.
Q: Operator balance sheets are in materially better shape than 12 months ago. How are higher commodity prices and improved borrowing capacities impacting the market? What kinds of business opportunities and activities are best suited for unitranche investment structures?
REXRODE: Unitranche combines the senior and mid-risk capital in one structure. Our transaction is a financial production payment structured as a temporary overriding royalty interest that is rate-of-return-driven to maturity, as opposed to a set amortization timeline. Perhaps as a proxy to mezzanine financing, our structure is quite attractive to small- to midsized operators simply because the traditional RBL providers have pulled back significantly in recent years.
Certainly, bank refinancing opportunities and acquisition funding opportunities have increased dramatically with higher commodity prices, as the math in many plays now makes sense. We are seeing a robust pipeline of opportunities from operators where RBL lending does not get them the capital amount needed for an acquisition with the flexibility for additional capital for development, or simply there are few bank options available.
In addition, the operator doesn’t want to sell down the deal to equity players and give up potential upside. Moreover, we are seeing many players with bank facilities that are requesting to be taken out. Increased commodity prices are allowing many of these refinancings to make sense, even with additional development capital layered on top.
Q: What characteristics do you look for in a management team? Are there certain types of assets that you prefer? How does Bluerock partner with clients to ensure win-win outcomes over the long term?
REXRODE: It is not a secret that most capital providers want to see an experienced technical team in place with their clients, specifically in the play being financed. BlueRock is no different. From the first meeting, it is always clear if the operator is experienced to take on a project, simply by reviewing and discussing their technical valuation work product and thesis for the upside work plan.
And it sounds cliché, but high character in the client principal is paramount when we consider a financing a client. The past two or three years have certainly tested the character of many of our clients with lower commodity prices, and our portfolio has remained strong because we feel like we have a group of clients that work with us constructively and do the right thing when times get tough. We are industry players, and we understand the oil and gas business can be challenging. We pride ourselves on working closely with our clients to bridge through rough market environments to get to a win-win for both of us.
We are not “loan to own.” In terms of assets, BlueRock is agnostic between oil and natural gas. We will review any project in the Lower 48. However, we do require substantial PDP in conjunction with a well-developed upside work plan, including proved undeveloped drilling, workovers, recompletions, refracs, waterfloods, cleanouts, etc. Also, because our deals are project-based and not supported by additional assets in the company, it is best if there are low-to-moderate general and administrative burdens against the asset, since the cash flow exclusively from the asset will drive the advance rate and payoff structure.
Q: Finally, let’s look at trends in the due diligence associated with upstream financing. Has Bluerock’s risk tolerance been impacted by the experience of the past 18 months? How do you seek to mitigate risk for both the lender and the borrower in a deal structure? Do you require operators to hedge their production?
REXRODE: I would say the experience from the past few years has caused us to be even more picky when it comes to potential deals. Again, because of the commercial bank pullback in RBL lending, we are seeing so many more high-quality opportunities that otherwise might not have been available. Clearly our deal structure–including significant PDP production–helps mitigate reserve risk. Our philosophy is to not put our principle at risk of loss if the upside development plan has limited success. This safety blanket has been especially helpful in a lower commodity environment, where upside development opportunities have been limited to being a nonstarter.
Our portfolio has performed very well through the downturn, derived from both lower-risk production profiles, as well as diligent monitoring and frequent communication with our operator clients. While we do not require price hedging with our clients, most of our clients do hedge price risk, and we take that into account when are assessing a potential investment. In terms of the ORRI that we own, we do hedge our commodity price risk against a meaningful percentage of our PDP production. Clearly, those hedges had a very positive effect on our cash flow during the price downturn.
Director | Energy Advisors Group
Q: After a slow start, the acquisition and divestiture market took off in 2021. What general trends drove the increased A&D activity? How were buyers and sellers able to come together to get transactions done? What was the profile of a typical seller, and who were the primary buyers as activity picked up?
MCKALE: A number of factors contributed to the rise in A&D activity throughout 2021. With global supply and demand shocks in 2020, the market slowed, and some were forced to sell assets or declare bankruptcy. A healthy 2021 transaction market was primarily driven by rising commodity prices. which brought some sellers to the market while valuations were in their favor and allowed others to catch their breath. Our clients have also raised political risk as a primary divestment driver: private companies have raised concerns over the potential for capital gains tax increases.
On the buy side, transaction activity was also propelled by the quantity of free cash flow being generated by healthier operators who are now better capitalized thanks to a renewed focus on debt retirement, leaner capital budgets and more acquisition opportunities. The buyer’s market has shifted during 2021; assets that were routinely transacting for forward PDP cash flow discounted at 20% or more in 2020 were realizing more competition as the year progressed, which lowered discount rates to a range of 10%-15% and had some paying for upside over the summer.
There remains a significant consolidation opportunity for those with the financial wherewithal. Large and small public independents remain active and continue to evaluate noncore asset sales. Private equity funds, having largely consolidated their portfolios, and institutional investors are also ready to put more money to work in an industry that has seen underinvestment for the past several years. The sellers are primarily made up of private and private-equity-backed entities taking advantage of strong transaction metrics. International firms have largely been selling assets as opposed to buying. Strategic (in-basin) buyers have been the most active buyers over the past year; the intrinsic value of the assets and potential to realize synergies in operations, as well as the technical understanding to be able to allocate value appropriately, are considerable advantages over out-of-basin counterparts.
Q: The past two years have seen significant consolidation among independent oil and gas companies, from “mergers of equals” to corporate acquisitions. How do you expect those M&A deals among the larger companies to ultimately impact A&D? What types of assets may become available as those companies shore up their new beefed-up portfolios and rationalize asset bases? What does that mean for midsized and smaller operators looking to make acquisitions?
MCKALE: Any large transaction–whether a corporate acquisition or a merger of equals–is a bellwether that other transactions are soon to follow. They indicate that capital markets are opening, buyer and seller expectations are falling in line, and other opportunities will be brought to the fore. Buyers may parse up their new position into core and noncore elements, or the new assets may deem some or all of the acquirer’s legacy position redundant. This trickle-down effect implies that each large transaction begets several midsized and smaller divestments.
Given limited capital budgets today, acquired assets must compete for capital with the buyer’s legacy assets. Well-capitalized small and midsize operators, who are often able to run leaner than large-cap counterparts, are well-positioned to ascribe more intrinsic value to the assets, and deliver top quartile offers to the seller.
Thinking about the major basins, the Permian–given its significant inventory of high-return locations–remains well-positioned at the top of most buyer wish lists, but the Eagle Ford and Haynesville are also vying for attention. The Eagle Ford has a number of small and midsize positions available, but a true basin consolidator has yet to emerge. Conversely, the Haynesville has been a target of Appalachian operators seeking to diversify their positions out of a technically robust but crowded Northeast gas market, while allowing for better exposure to global export markets via the U.S. Gulf Coast. Business development teams should expect to see a large number of assets coming to the market in these areas over the near-term.
Q: Stronger commodity prices mean higher reserve valuations and borrowing base determinations as 2021 draws to a close. What is the market seeing in terms of property pricing dynamics? Do you expect asking prices trend higher in 2022? Will buyers and sellers still be able to reach common ground with respect to property acquisition values?
MCKALE: Restrained budgets offering limited organic growth, along with rising commodity prices, are leading to excess free cash flow in the market. Companies looking for scale are turning more to acquisitions than the drill bit. As a result, we are seeing more competitive tension in our processes now than we were six months ago, and that has given rise to stronger valuations from prospective buyers. Acquisition discount rates are trending lower. Conversely, multiples for current cash flow, acreage, production and reserves are trending higher. Current cash flow is a key performance metric and most transactions, outside of the more-competitive Permian and Haynesville, remain significantly weighted toward PDP valuations.
Asking prices have certainly trended higher in 2021, and bids are following suit. Higher crude and natural gas price decks have allowed that bid/ask spread to narrow and should extend this stout transaction market in the near term. There are creative structures–deferred or contingent payments for example, based on buyer activity levels or commodity price lookbacks–that can bridge the gap, allowing sellers to benefit from the robust nature of the current market, and assuming they believe in the upside, receive value for tangible forward development opportunities, while protecting the buyer’s near-term transaction economics.
Q: Although overall business conditions are robust on most fronts, upstream capital flow remains fairly tight. How could financing availability and terms weigh on A&D dealmaking in 2022? Are capital providers and advisory firms requiring more technical due diligence? Is the fact that so many large public operators are electing to operate out of free cash flow impacting the A&D and the types of properties coming on the market?
MCKALE: To state the obvious, without financing, many assets will not transact, and we have seen a wave of lenders and other institutional investors exiting the energy business over the past several years. That having been said, the financial institutions that know how to weather inevitable industry volatility are certainly more comfortable today. Of the advisers that remain, many have acquired or built their own technical teams to work with clients to ascertain asset value and collaboratively determine an appropriate value proposition for the market. With many public operators basing their budgets on current free cash flow, material value allocation to upside beyond PDP has yet to materialize as it had in years past. This is especially true of mineral interest offerings, which have been impacted as much or more than working interest valuations and speaks to a buyer’s inability to put value on the upside because of reduced activity levels for many buyers.
However, perspective is everything. Receiving PDP PV15 today may work out to considerably more than “PDP PV10 plus upside” as recently as 12 months ago. In any event, prospective buyers have been paying little (if anything) for upside over the last two years, although we are seeing signs that increased competition in formal processes has resulted in value allocation for future development provided the asset is supported by a clear vision with low-cost, low-risk upside–including published budgets, permits and AFEs, and especially rig activity.
Value for upside can be achieved, provided an advisor does two things:
- Maintain credibility with both the buyer and seller by promoting consideration for real, tangible upside development by utilizing hard data, including performance analogues and evaluation of area activity to determine a reasonable pace of development; and
- Maximize competitive tension through suitable market outreach to ensure strategics are aware of the opportunity, and bring in new entrants that can value the position accordingly.
Q: What are the technology trends in A&D technical analysis (engineering, geology and land)? How are advances in areas such as AI, machine learning and cloud computing improving technical analysis and A&D transactional workflows? What are the benefits for sellers and buyers of leveraging state-of-the-art A&D software tools?
MCKALE: There has been a tremendous increase in the use of data analytics and associated software in A&D over the past five years. This statistical analysis coincident with the ongoing design-of-experiment being put forward by operators has resulted in an optimized completion design (proppant/fluid volumes and types, cluster and stage spacing, etc.), enhanced well performance (decline curve analysis), and efficient development planning across large swaths of most unconventional basins as it relates to well spacing, multibench development and overall play delineation.
It has also allowed geoscientists to study and correlate with more precision and greater efficiency than ever before. Mapping services have been integrated such that almost every piece of technical information can be georeferenced and mapped to define play trends and characteristics.
As it relates to transactions, these tools allow sellers to convey a better story surrounding their assets. Through careful analysis, sellers may be able to pinpoint the factors that explain key performance metrics, and steer prospective buyers to value. Buyers are more educated on the causes of past performance and the potential of future development and will be able to churn through analytical evaluations of many assets quickly and easily, tailored to their individual preferences and corporate assumptions, prior to allocating significant human resources to study each opportunity in more detail.