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Investing in distressed energy debt

Mon Mar 9, 2015

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Vladimir Jelisavcic of Bowery Investment Management sees opportunities in today's dislocated energy market.


  Vladimir Jelisavcic of Bowery Investment Management
Vladimir Jelisavcic
(Photo: Bloomberg)

Energy plays of all shapes and sizes have been the focus of considerable investor attention following the 50% decline in crude oil prices. Traditionally, distressed debt investors focus on valuation metrics, such as EBITDA multiples and cash flows. We take those metrics into account, but our view is that investing in oil and gas distressed debt securities should be an asset-driven approach. We focus on proved reserves also known as PV-10. This is an SEC mandated measure of the quantity and value of oil and gas reserves with a 90% or greater probability of being commercially recoverable. PV-10 includes both Proved Developed Producing ("PDP") and Proved Undeveloped ("PUD") reserves. Balance sheet analysis is also critical, since companies in need of liquidity are vulnerable to borrowing on difficult terms that may be negative for unsecured bond holders. The current dislocated energy market offers opportunities to invest in distressed debt of companies trading close to liquidation value with reasonably liquid balance sheets, such as Sandridge Energy. For simplicity, we will refer to crude oil, natural gas, and natural gas liquids as equivalent units of oil, expressed as barrels, or "bbls".

Evaluating Reserve Assets

We focus on the two main types of proved reserves that contain most of the value. The first is PDP. These are lower risk, higher quality reserves that measure the value of wells that have been drilled and that are actually producing oil. The vast majority of capital used in the exploration and production ("E&P") business is expended on drilling and completing new wells. The PDP reserves represent proved producing assets where drilling and completion expenditures are sunk costs, and oil is flowing as a result of these investments. PDPs represent the lowest risk type of oil reserve asset. The PDP is the present value, discounted at 10% of the difference between the future revenue per bbl, and the future marginal cost per bbl, projected forward based on expected decline curves of producing wells as estimated by an independent reserve engineer. Established independent reserve engineers such as Netherland Sewell and Ryder Scott are conservative and generally underestimate actual proved reserves. Their reports are publicly disclosed as exhibits to an E&P company’s 10-K. Materially incorrect and misleading opinions expose reserve engineers to legal liability far in excess of the fees earned on any engagement. This imbalance between the value of an engagement and the potential legal liability provides a strong incentive for reserve engineers to conservatively estimate asset values, and provides investors with a reasonable basis for evaluating reserves.

PDPs are reported annually in each reporting company’s 10-K, using the average oil price on the first day of each month for the previous twelve months. For 2013, SEC pricing was $93/bbl. Sandridge reported a $2.4 billion PDP value as of December 31, 2013. We make three adjustments to this number. First, we adjust the 2013 PDP value for the estimated growth in proved physical reserves over a one year period. This estimated growth is the difference between the natural depletion of wells that were producing as of December 31, 2013, and the increase in production from new wells that were drilled and completed during 2014. We estimate that PDP reserves will grow by 28% to $3.1 billion as of December 31, 2014, using 2013 SEC prices. This is reasonable given Sandridge’s 2014 capital expenditure guidance of $1.5 billion, $1.3 billion of which relates to exploration and production. Second, we reduce the $3.1 billion PDP by the $500 million estimated value of PDP reserves held by non-controlling interests to arrive at a net 2014 value of $2.6 billion. Third, we take this growth adjusted net PDP and use the average of the price of the next 12 monthly futures contracts that trade on the NYMEX, known as the "12-month strip" price. At the time of this writing, the average 12-month strip price was $59/bbl. It is difficult for us to accurately calculate true NPV, since we don’t have access to the granular data and projections used by the independent reserve engineers that drive assumptions behind the shape of future decline curves. As a proxy, we compare the estimated cash margin of the reported PDP, using SEC prices, with the estimated cash margin using the 12-month strip price. Cash costs that determine the margin include lease operating expenses, taxes and transportation. For Sandridge, we estimate these variable costs are approximately $12/bbl. Using the 2013 SEC price of $93, gives us a cash margin of $81/bbl for 2013 (93–12 =81). Using the 12 month strip price of $59, gives us an estimated forward margin of $47/bbl (59–12 =47). The ratio of the forward margin to the historical margin is 58% (47/81). We also work with an energy consulting firm that reviews publicly available data on well performance as an additional check on our estimates. To summarize, we estimate that Sandridge’s PDP reserves have a liquidation value of $1.5bn (2.4bn x 128% =3.1bn - 0.5bn =2.6bn x 58% =1.5bn).

Sandridge’s total PV-10 reserves as of December 2013 were 377 million bbls, of which PDP reserves totaled 206 million bbls. The 171 million bbls remaining of proved reserves relate mostly to PUD reserves. There are 130 million bbls of PUD reserves that are net of non-controlling interests. These net PUD reserves should have also grown by 28%, and should be about 166 million bbls as of December 2014. We estimate that even in this depressed environment, PUDs are worth at least $1/bbl, or $166 million.

Liquidity and Secured Debt

One of the most critical assets for an E&P company during times of depressed oil prices is liquidity. Many smaller E&P companies that grew rapidly in the last three years funded growth by issuing high-yield bonds. Many of these companies outspent operating cash flow and invested heavily in aggressive drilling programs. This type of company will usually not have any significant amounts of cash on its balance sheet. Leveraged companies with low levels of cash often depend on oil reserve based revolving credit lines or "RBLs". The problem with RBLs is that lenders regularly re-appraise the value of oil in the ground. This re-appraisal is called a "redetermination" and is calculated semi-annually using an agent bank’s own oil price assumptions, geological assessment, and advance rates. This calculation of the maximum amount of credit that a bank will lend on the reserve assets is called a borrowing base. Current borrowing bases were redetermined last fall in a $70 to $85 oil market. The upcoming redeterminations in a $59 12-month strip price environment will constrict liquidity. Our analysis shows that most borrowing bases will be reduced by 20-30% this spring from the prior redeterminations last fall.

In extreme cases this reduction in liquidity will cause weaker E&P companies to default. In most other cases, banks will work with E&P borrowers, but are likely to pressure them to "term out" RBLs by borrowing 2nd lien term loans, using loan proceeds first to pay down existing RBL borrowings, then keep any remaining cash on the balance sheet. This is a significant risk factor for bond investors. Most conventional high-yield bond indentures do not contain meaningful covenants that restrict an E&P company’s ability to "prime" unsecured bondholders by incurring secured debt with priority over unsecured bonds. The key question becomes what kind of 2nd lien term loan financing does a company have access to? Weaker borrowers will not have much of a choice. For example, Resolute Energy Corporation had $335 million drawn on its RBL and its bank group pressured Resolute to reduce the bank group’s exposure. As a result, Resolute recently borrowed $150 in the form of a 2nd lien term loan from a group of investors led by a hedge fund and used the proceeds to pay down a portion of its RBL. The financing was expensive and onerous. The coupon was 11% (Libor + 10%, with a 1% floor) and contained a very restrictive covenant that prohibits secured debt from exceeding the value of PDP reserves. Stronger companies like Sandridge with $590 million in cash, and an undrawn RBL have much more flexibility.

Sandridge’s undrawn $900 million RBL was last redetermined on October 22, 2014. The RBL contains financial covenants, including one that requires total funded net debt not to exceed 4.5x trailing EBITDA. Since Sandridge is likely to be drawing down its cash balance over the next few quarters, the company is at risk of violating this covenant in the second half of 2015. Bank groups have been working cooperatively with stronger E&P companies that have a significant ratio of PDP reserves to total debt. For example, EXCO Resources, Inc. recently amended its RBL and reduced the borrowing base by 19% from $900 million to $725 million. EXCO also removed the consolidated leverage ratio covenant through September 2016. EXCO’s December 31, 2014 PDP reserves (using 2014 SEC pricing) are $705 million. Given our estimate of the liquidation value of Sandridge’s net PDP reserves of $1.5 billion, we think Sandridge will be able to amend financial covenants with its bank group and redetermine its borrowing base close to the current $900 million amount. If Sandridge terms out a portion of its RBL, it should be able to access the conventional syndicated term loan market with reasonable financial covenants and pricing. This increase in liquidity will buy the company time to operate until oil markets begin to recover.

Hedge Value

Another important asset that many E&P companies have is the value of hedges. Since we valued the PDP reserves at the 12 month strip price, we need to add the market value of hedges to our analysis. Sandridge has two types of hedges, swaps and three-way collars. For swaps we can simply take the difference between the swap prices and the 12 month strip multiplied by the hedged volumes. A three way collar is a short call, a long put, at a high price, and a short put at a lower price. We can ignore the out-of-the-money short call, and estimate the value of the collar as the difference in strike prices between the long and short puts, multiplied by the notional volumes. Our analysis of Sandridge’s hedges comes up with a value of $377 million.

Conclusion

We think that Sandridge is a survivor. Its large asset base provides substantial downside protection for unsecured bondholders. Sandridge is one of only a few E&P companies that we know of that has no funded secured debt, and a substantial amount of cash on its balance sheet. So to summarize, we believe Sandridge today has a liquidation value of $2.48 billion, consisting of $1.5 billion of PDP reserve value, $590 million of cash, $377 million of hedge value, and $166 million of PUD value, less $150 million of liquidation costs. This compares to a bond market value of $2.3 billion, based on $3.2 billion face amount of bonds x 72% (trading price of the 7.5% bonds due 2023).

Crude oil markets will not stay at depressed levels indefinitely. US Shale producers have overtaken Saudi Arabia as the global swing producer and we have seen the industry respond to the correction in oil prices by announcing meaningful reductions of capital expenditures. We expect that slower production growth along with the potential for a demand response driven by lower oil prices will eventually rebalance markets and restore the stability that has been missing for the past several months. Until that happens, there is a unique opportunity to buy into asset rich businesses trading near liquidation value with reasonable balance sheets through investments in distressed debt. This is one of the most exciting opportunities we have seen in our markets in many years.

Vladimir Jelisavcic is founder and managing principal of Bowery Investment Management, a distressed debt hedge fund based in New York.

ISSN: 2151-1845 / CDC10004H



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