Energy Alert
January 5, 2015
A Dozen Ways to Stretch Your Borrowing Base
Seasoned residents along the Gulf Coast know how to handle the summer hurricanes that blow in from the other side of the Atlantic. Get to high ground, batten down the hatches, and ride out the storm until it passes. The Gulf Coast is home to the oil patch, which also sees its share of storms hit oil markets rolling in from the Middle East. The latest storm hit the oil markets on Thanksgiving Day following OPEC’s meeting in Vienna on November 27, 2014. Oil prices that had been steadily dropping from a high of $110/bbl WTI since June dropped 10 percent over Thanksgiving Day into the mid-$60s – and continue to head south now. Seasoned oilmen know that just like the Gulf’s hurricanes, in time, this commodity storm too will pass. Similar to weathering hurricanes, the best advice from these oilmen is to conserve cash, hunker down and survive until prices come back.
American Eagle Energy Corporation’s announcement on New Year’s Eve is a good illustration how some producers are already battening down the hatches. The company announced it has suspended its 2015 drilling budget, paid off outstanding obligations under its senior credit facility, and liquidated its crude hedges through December 2015 generating $13 million. American Eagle’s remaining debt is $175 million secured 11 percent notes, which the company notes do not have any maintenance covenants. The company is focused on capital discipline and maintaining liquidity. In other words, hunkering down and hoping to survive until the storm passes.
Conserve Cash and Maintain Lines of Credit
Not all producers have the option of shutting down or temporarily abandoning their bank relationships. Bank lines are a critical component in most oil and gas independents’ capital structure. Ever since the early OPEC driven price gyrations in the late 1970s, independents have accessed bank credit under loans structured as reserve-based revolving lines of credit. The amount of credit available to the producer under this structure is measured by the collateral value of the producer’s proved oil and gas properties, known as the “borrowing base.” Producers have access under their revolving lines of credit up to the borrowing base amount which is redetermined by the lender semi-annually. Most borrowing bases today are reset around each October 1 and March 1. If commodity prices remain low, and if producers slow down their capital expenditures to conserve cash thereby slowing the timing for bringing additional wells on production, come this March they are likely to see severe reductions in their borrowing bases.
Below are some of the options that may help producers stretch their borrowing base and/or help conserve existing credit lines:
1. Jump to the Front – working with lenders now ahead of the scheduled borrowing base redetermination date to “reaffirm” current borrowing base amounts.
2. Extend and Pretend – extend the borrowing base redetermination date and maturity date in hopes prices rebound before the loan matures or the borrowing base is re-determined.
3. Discount the Discount – Lower the discount value for determining the present value of reserves thereby increasing the total present value.
4. Collateralize the Near Term – request credit for the value of the next six months’ production, which is normally omitted (see why below), to be added into the borrowing base (with a monthly reduction feature).
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5. Slice and Dice – restructure borrowing base loans into conforming and non-conforming “stretch” tranches (the stretch lenders will expect to be paid for the higher risk).
6. Hedge Above the Deck – hedge production further out into the future at prices above the lender’s current price deck to boost the borrowing base.
7. Trim and Roll Short Hedges – monetize any hedges within the first six months or roll them into the future.
8. Monetize Long Hedges – to the extent the liquidation value of hedges beyond the first six months exceeds their incremental borrowing base credit, these hedges can be turned into quick cash – without decreasing the borrowing base value.
9. Convert Non-Borrowing Base Reserves to Cash or Future Production – where borrowing base credit is not given to non-proved reserves (i.e., reserves classified as possible or
probable) or excess PDNP and PUDs, if cash is king, better to sell them now if there is a buyer for the assets. Alternatively, such acreage can be farmed out to develop the properties with other people’s money.
10. Sell and Lease Back the Kitchen Sink – Certain assets are not given any borrowing base credit such as gathering systems, processing facilities, and compressors, all of which can be sold for cash and, where needed for operations, leased back.
11. Become Best Friends with a Mezzanine Lender – Stretch and mezzanine lenders were feeling unloved in 2014, getting priced out of deals by aggressive senior and high yield debt providers. In 2015 they will be the belle of the ball to refinance, restructure and recapitalize companies for whom options 1-10 are just not enough.
12. Become Best Friends with a Bankruptcy Lawyer – In case options 1-11 are just not enough. Need I say more?
Caveat, Caveat, Caveat!
These options are stop-gap measures. If commodity prices stay low for an extended period there may be no way to forestall a reduction in the borrowing base and the resulting mandatory principal amortization. One size won’t fit all. Not all options work for all producers. Nor should any one producer utilize all options. Every option requires lender consent and cooperation. In larger facilities with a syndicate of lenders such actions may require the consent of a majority of lenders and, in some cases, unanimous consent. Choosing the best option(s) depends upon the producer’s current financial condition, capital needs, and expectations for future commodity prices. Involve your lender early and keep lines of communication open. The sooner the process is started the greater likelihood for success.
The following explanation of how borrowing bases are calculated and operate under a reserve based loan will help explain in more detail the options below.
Basic Borrowing Base Mechanics
Borrowing bases have historically been set by the lender in its discretion. Originally, borrowing bases were calculated on the same underlying parameters that determined the maximum loan amount under a fully funded term loan – with one structural difference. Under a term loan, the borrower begins amortizing principal soon after the funds are advanced. Under a revolving loan, the borrower has no principal amortization schedule, and in fact can borrow up to the full amount of the borrowing base on the last day prior to maturity. The borrowing base under a revolver serves as a way to convert the loan to an amortizing term loan on each borrowing base redetermination date.
With periodic redeterminations of the borrowing base (typically every six months), the borrowing base the bank looks at the borrower’s most recent
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engineered reserve report and estimates how much it would be willing to loan against that collateral six months into the future when the next redetermination is scheduled to occur. In other words, if everything goes as forecasted, even if the borrower drew the revolver on the day before the next scheduled redetermination up to the full borrowing base limit, the bank should be “fully secured.” Upon such redetermination however, to the extent outstanding principal under the revolver exceeds the newly determined borrowing base (i.e., the projected collateral value six months out), additional collateral must be pledged or mandatory principal payments will be required to bring the principal outstanding in line with the new redetermined borrowing base, so that at the next redetermination date, the loan is “fully secured” and the process repeats.
While this structure looks very efficient in theory, in practice things can get messy quickly. Typically, a borrower has pledged everything it owns – especially everything that has been classified as “proved reserves.” If because of a borrowing base deficiency a producer is required to start making monthly principal paydowns, cash flow is going to be diverted from other obligations. Typically the producer’s first option will be to defer discretionary capital expenditures – future drilling and completion operations. But these are the very operations that are needed to replace current production that is producing the cash flow to pay down the principal and support the borrowing base. In the short term this may be a viable option, but if cap-ex is deferred to too long, the producer is drilling a hole from which he can never escape.
With the borrowing base calculated to be the collateral value at the next scheduled borrowing base determination six months into the future, the first six months of projected production is not counted in the borrowing base. In other words, the producer receives no collateral credit for its first six months of projected production under any borrowing base determination. Accordingly, a bank will typically advance less on a revolver than under an amortizing term loan. Under a variation of the traditional borrowing base structure, some banks will “stretch” and set the borrowing base at the properties’ current value at closing. Under this structure however the borrowing base is reduced monthly by equal increments (the “borrowing base reduction amount”) so that by six months out the “stretch borrowing base” equals the projected collateral value at such time.
Borrowing Base Algorithms
Each bank has its own proprietary algorithm for determining the amount it is comfortable loaning to its borrowers. Many of the variables are common among energy lenders. For example, most lenders will advance up to 65 percent of the value of the producer’s proved developed producing reserves (PDP), plus 35 percent of proved developed non-producing reserves (PDNP), plus 25 percent of proved undeveloped reserves (PUD). Provided that not more than 40 percent of the borrowing base amount can be comprised of value attributed to the producer’s PDNP and PUD reserves. No borrowing base credit is given for unproven acreage classified as “probable” or “possible.” Under such a formula, a borrower with a lot of undeveloped shale acreage and very little current production may receive a higher haircut on its PUD reserves than a producer in the same field with a lot more production (PDP) and the same amount of PUD acreage.
Determining the borrowing base is not as simple as looking at the lower right hand corner of the summary page on the producer’s reserve report for the total PDP, PDNP and PUD reserve values and multiplying them by the bank’s reserve percentages. As the concept has evolved over the years, rigorous risking analysis by the bank’s engineers include comparisons of proved producing versus proved undeveloped production, well value concentration, geographic concentration, reservoir decline profiles, basis differentials and transportation costs, lease operating expense, plugging and abandonment costs, and
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credit enhancements through commodity price hedges. All of these variables (and more) to varying degrees are included within each bank’s algorithms to arrive at its determination of the borrowing base. Under the standard borrowing base loan, the borrowing base is redetermined semi-annually. As the concept evolved over the years, bankers, and later, borrowers, negotiated the right to trigger a special (“wildcard”) redetermination within each borrowing base period or at least annually. The borrower wanted the ability to be able to access additional availability under its facility in the event that the value of its reserves significantly increased through enhanced production or prices, or more typically, in connection with a material acquisition of producing reserves. Bankers, not surprisingly, wanted the ability to reduce the borrowing base in the event of a significant loss of production, commodity price declines, or sale of producing reserves. Notwithstanding this tripwire, bankers have over the years been very reluctant to exercise this right and pull the trigger on the producer’s loan.
Discount Rates of Future Reserves
In arriving at the present value of a borrower’s oil and gas reserves to be produced over the life of the loan (and longer), a lender will discount the value of future cash stream by some factor. The discount rate used by the lender will directly impact the amount of the borrowing base, especially for longer-lived reserves. Up through the end of the 1990s most energy banks used a ten percent per annum discount rate to arrive at a present value for future production (PV10). The discount rate was not particularly tied to cost of capital, future expected rates of interest or even to the current interest rate. Even when the banks’ prime interest rate was at a high of 20 percent in the early 1980s, the discount rate used by the banks for calculation of present value for a borrower’s reserves remained at 10 percent. Around 2004, some energy banks began to use a nine percent discount rate (“PV9”) to evaluate reserves for competitive reasons to juice their borrowing base numbers.
Knowing the basics of borrowing base mechanics, what options do producers and their lenders working together have to conserve capital and provide support for a higher borrowing base to prevent mandatory principal payments under a borrowing base deficiency?
1. Jump to the Front
Even in good times, borrowing base season involves a lot of work and discussion to determine the new higher borrowing base amount. When the likelihood is borrowing bases will be reset at lower amounts, odds are there will be a lot more discussions – some perhaps heated – over the proper evaluation of a borrower’s reserves and prospects. By the time this March rolls around, bankers and producers will be having serious conversations over the proper borrowing base value for their collateral. Human nature being what it is, lenders have a finite amount of good will, empathy and patience. In addition, as March draws near, the more “distressed” borrowing base loans a lender is dealing with the less leeway that lender will have to make exceptions for any particular producer’s given collateral package. If a producer anticipates that commodity prices are not going to appreciably improve in the next few months, it may be better strategically to accelerate the redetermination before his lender is inundated by the tsunami of other spring borrowing base redeterminations. In order to get a jump on this process, the producer will have to have updated its reserves engineering and be able to provide the lender with whatever additional information may be requested.
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2. Extend and Pretend
During the Great Recession when the price of West Texas Intermediate dropped from $145/bbl to $30/bbl in less than six months from July 2008 to December 2008, many expected a blood bath during the Spring ’09 borrowing base season. While there was pain, the massacre did not happen. To a large extent, the lenders’ financial situations were as weak, or weaker, than their producer-borrowers. Following the financial crisis when banks were reluctant to lend to other banks, the last thing a bank wanted was more “non-performing” loans on its books. Rather than face the consequences of reduced borrowing bases or busts in financial covenant tests, banks and producers entered into amendments extending the maturity dates, temporarily waiving compliance with financial covenants and holding borrowing bases steady (that is, neither increasing nor decreasing the amount). These agreements were known off the record as “Extend and Pretend.” Because prices bounced back quickly following the lows in December to above $70/bbl by May, 2009, the strategy worked for both the banks and the producers. Depending upon the lender’s expectations for future commodity prices six months out from March, it may again be in both the lenders’ and their producers’ best interests to hold borrowing bases at current levels. Any reduction could trigger borrowing base deficiency payments which if the producer is unable to meet will trigger defaults and non-performing loans on the banks books.
3. Discount the Discount
Depending upon the current discount rate and reserve life profile for a producer, reducing the discount rate could lead to a higher present value for proved reserves. Most lenders and companies publically reporting under SEC guidelines use a PV10. As indicated above, most energy lenders have converted to PV9 in order to arrive at a higher borrowing base. Some banks report using PV7 and onereported using a PV6 discount rate. If a bank is currently using a high discount rate, merely decreasing the present value discount percentage can produce greater “value” and a higher borrowing base. For example, the present value of a $100 million property ten years from today discounted at ten percent per annum (PV10) is equal to $3.855 million, at PV9 it is equal to $4.244 million and at PV8 it is equal to $4.632 million. PV8 is almost twenty percent higher than if discounted at PV10 (assuming all other variables remain the same!). Of course given the multiple variables in the calculus that comprises the borrowing base, a bank can use a lower present value discount rate, but be more conservative, for example, in its advance rate against total proved producing reserves and still arrive at a lower borrowing base amount than a bank that uses a higher PV discount rate. Accordingly, discounting the discount only works if all other variables in the lender’s borrowing base algorithm stays constant.
4. Collateralize the Near Term
Because the first six months’ production is disregarded in a conforming borrowing base calculation, a producer gets no credit for near term value. One way to capture this value is to use a reducing borrowing base formula which gives full credit for the production over the following six months and builds in a monthly amortization schedule which after six months of such reductions would be equal to the amount on a standard borrowing base. Some credit agreements are currently structured with a monthly reduction amount which when set at $0 is essentially the same as the standard borrowing base. It would not even require any amendment to implement this option for those producers with this feature built into their credit agreement. For others, the borrowing base redetermination letter may suffice to document the change in structure. At most, this change can be accomplished with a simple amendment to the loan agreement.
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5. Slice and Dice
A structure that energy banks used in the early 2000s to compete with mezzanine and private equity debt providers was to offer producers a standard “conforming” borrowing base, priced at market for similar borrowing base loans, and a “stretch” borrowing base which would be priced at a higher coupon, but competitive with or lower than mezzanine debt pricing. The attraction to this structure was that it could all be documented under the senior loan documents and didn’t require a separate loan or mortgage documents, thereby reducing costs and time to implement this structure. The stretch piece was documented as a separate tranche (Tranche B) under the senior loan with a shorter maturity (generally less than 18 months) than the conforming tranche (Tranche A). The proceeds of the stretch portion of the loan would typically be for an acquisition or development drilling. The expectation being that the loan proceeds properly invested by the producer would result in a higher “conforming” borrowing base in succeeding redeterminations enabling the producer to pay off the “stretch” loan earlier than its stated maturity.
In the current situation where the determination of a conforming borrowing base is certain to lead to a reduction, it may be attractive to tranche the borrowing base to a conforming piece and a stretch piece. A producer should expect that such an accommodation would come at a price with the Tranche B portion, and perhaps the Tranche A portion, carrying a higher coupon. Whereas the earlier stretch revolvers anticipated value growth through operations and increased production, the thesis supporting a stretch in current markets would be expectation of a rebound in commodity prices. Of course, if the lender doesn’t foresee prices rebounding within a relatively short period over the next 12-24 months, this structure might be better characterized as a variant of the Extend and Pretend to give the producer additional time to right the course before any principal repayment is triggered.
6. Hedge Above the Deck
Lenders’ estimates of their producers future reserves is based on a “price deck” of estimated future prices of crude oil, natural gas liquids and natural gas, discounted on a present value basis. Public companies report reserves on an SEC basis using a backward looking 12-month price average. Some mezzanine lenders who measure their loans against an asset coverage ratio will look to the average closing price of futures contracts over a fixed period as the yardstick to value a producer’s reserves. Energy banks use a conservative price that may be escalated over time as the basis for calculating the borrowing base (a bank’s “price deck”). To manage the bank’s commodity price risk of underwriting production loans with maturities up to three to five years out into the future the price deck is conservatively “below market” which directly affects (reduces) the available borrowing base. Banks can adjust the price deck up if a borrower is able to “lock in” future prices higher than the bank’s price deck through commodity hedges. If the bank’s price deck as of the March redetermination is less than future hedge prices, it may boost the borrowing base to hedge additional production, provided the costs of obtaining such hedges is less than the incremental increase in the borrowing base. Note that most reserve based loans prohibit producers from hedging more than a fixed percentage of future projected production (e.g., no more than 85 percent of reasonably estimated total production for a term no more than 48 months). Where a borrower is already at the limits of this loan covenant, additional borrowing base value may be created by getting the lender to waive the restriction on percentage or length of maximum hedges that can be put in place.
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7. Trim and Roll Short Hedges
Because near term production is not valued under the standard borrowing base calculation, any hedges for the next six months following each redetermination provide no support to the borrowing base. Producers could either roll these hedges to future contracts more than six months into the future or monetize these hedges and turn them into cash. Assuming the producer isn’t in need of short term cash and is able to roll the contracts out to future dates above the bank’s price deck, rolling short term hedges would provide support for a higher borrowing base by March.
8. Monetize Long Hedges
There is a fairly liquid market for hedges up to 60 months out. How much support such hedges provide the producer’s borrowing base (to the extent they are above the lender’s price deck) will vary subject to volumes hedged, expected future production levels, the strike price over the price deck and length of the hedge contracts. Whether or not a producer has hedge contracts with current liquidation value above the incremental support to its borrowing base cannot be answered without the lender’s input. Given current commodity prices, however, yesterday’s PUDs may not get drilled and may be reclassified as “probable” reserves. Accordingly, a borrower that had hedged volumes based on expectation of converting last year’s PUDs to PDPs in 2015 through future drilling, may find themselves “over-hedged” when such PDP volumes can no longer in good faith be expected to materialize. It should come as no surprise that lenders are not likely to give enhanced price deck value in the borrowing base to hedges that no longer cover proved reserves. And, in fact, downgrading PUDs to possible reserves may even trip up the borrower’s loan agreement covenants not to hedge in excess of certain thresholds of reasonably expected future production. To comply with loan covenants, some producers may be required to liquidate a certain percentage of future hedged volumes or else seek a waiver of these covenants.
9. Convert Non-Borrowing Base Reserves to Cash or Future Production
As noted in the discussion on borrowing base mechanics, typically lenders restrict the borrowing base value of PDNPs and PUDs to not more than 35 percent and 25 percent respectively, and total borrowing base number cannot exceed more than 40 percent credit for such reserves. No borrowing base credit at all is given to the producer’s probable and possible reserves. For a producer whose collateral mix is cash poor but land rich (i.e., light on PDP but heavy on PDNP, PUD, probable and possible reserves) much of its oil and gas properties are not contributing to the borrowing base. Such non-producing acreage, if it is not held by production, could even require additional capital to maintain the leasehold under continuous drilling obligations. In such case, selling or farming out the non-borrowing base properties may serve to raise cash or decrease capital needs or both. Many producers will find that their PDNP and PUD reserves are on the same acreage as the PDP reserves that serve as the bulwark of their borrowing base. Cleaving such non-producing acreage is more complicated, requiring that producing well bores be retained by the seller while the non-producing acreage is sold off. As an alternative to an outright sale, a producer may want to explore farming out such acreage for a back-in working interest after payout. Such transactions will raise issues regarding consents to assign, preferential rights, and uniform acreage maintenance provisions. The more complicated such transaction becomes, the greater the execution costs and more difficult it will be to obtain the lender’s cooperation – not to mention a buyer’s interest at making an offer “fair” enough to justify the process. But it is better to salvage some value for these assets than to lose them from lack of
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continuous drilling or non-consent penalty fees. To quote the great 1970s philosopher and back-up pianist for George Harrison, Billy Preston, “100 percent of nothing, leaves nothing.”
10. Sell and Lease Back the Kitchen Sink
Reserve Based Loans are called “reserve based” for a reason. The loans are underwritten by the producer’s oil and gas reserves. That is not to imply that lenders won’t take liens on the producer’s other assets. In fact, the lender’s preference is to take liens not only on the reserves but on “all assets” of their borrower. Although other assets may be encumbered to secure the reserve based loan, the market value of such non-reserve collateral does not go to the borrowing base bottom line. For example, while a gas gathering system is critical to getting the producer’s gas to market, a lender rarely includes any borrowing base value for the system, even when the producer may be transporting third party gas for co-working interest owners for a fee. Borrowers may own other production equipment that is necessary for production such as processing facilities, drilling rigs, compressors and other high value capital assets, but again, no borrowing base credit will be applied to such assets. It is not unusual for offshore producers to separately finance the onshore production facilities and offshore gathering and umbilicals from their leases. Until recently, the installation costs for such infrastructure for onshore producers have not been significant enough to require separate financing. In many older fields the value of such assets may be unrealized. A producer can convert such assets to ready cash if it can find a third party buyer or an equipment financier willing to monetize the assets in an outright sale or a sale and lease back transaction. Most loan agreements prohibit the disposition of such associated equipment and restrict the amount of capital leases and sale leaseback transactions a borrower can have. Accordingly, this strategy will require the lender’s consent and involvement. In cases where the lender has an affiliate equipment leasing finance company, such consent may be more readily obtained.
11. Become Best Friends with a Mezzanine Lender
If the first ten options fail or are not available to a producer, there are alternatives, for a price. Mezzanine capital competes best with senior secured reserve based revolvers when prices are in flux, whether rising quickly or falling. Mezzanine debt typically takes the form of non-revolving second lien secured line of credit with higher interest rates and often an equity kicker component in the form of warrants or an overriding royalty interest. Many mezzanine lenders in early 2014 found it hard to compete with deal-hungry senior lenders and public debt markets as commodity prices held relatively firm. By the end of 2014, a number of private equity funds were formed, and others were in the process of raising investor capital to meet the expected demand for stressed and distressed oil and gas producers. In a distressed second lien scenario much greater financial and operational control, including board observation rights and tighter trip wires in terms of covenants and use of proceeds are imposed on the producer. In a restructure scenario, the mezzanine debt will be used to pay down the first lien below the borrowing base amount to provide the borrower time to get its financial house in order (and hope commodity prices turn around). Senior lenders will permit mezzanine second lien debt behind their first lien secured revolver, but the borrowing base will take a hit.
Generally, where first lien lenders permit a second lien to come in behind them they will reduce the senior borrowing base by 25 percent of the amount of second lien debt. Therefore, accessing mezzanine debt won’t “stretch” a producer’s borrowing base. Quite the contrary, it will cause a reduction. But if access to capital is the ultimate goal, a reduction in the borrowing base may be a
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deal that cannot be passed up. It is a deal that will come at a significant price and significant negotiation. A producer is well advised to be selective in choosing its mezzanine lender.
12. Become Best Friends with a Bankruptcy Lawyer
In case options 1-11 are not available to a cash strapped producer, there are other choices, but at potentially significantly higher costs to the producer’s owners. Private equity, which is more expensive than mezzanine debt, can be obtained but a producer will be expected to give up a considerable portion of its equity up front. The producer may be able to recoup some of the equity back from the private equity in the future but only if significant financial and performance hurdles have been met. For other producers protection from creditors under the jurisdiction of federal bankruptcy courts may provide some refuge in hopes of waiting out the storm.
Conclusion
The oil and gas business has been and always will be an industry that is constantly in need of capital. With a continuously depleting asset, standing still is not an option, at least not in the long term. Failure to continue to drill and replace existing reserves can become a death spiral where production drops, causing borrowing bases to fall below outstanding borrowings to the point where the producer can no longer afford to repay the borrowing base deficiencies out of current cash flow. If this latest oil price storm is more like the price collapse in 2008 or 1999, it’s certain to leave a wake of destruction but its short term duration will pass as quickly as a late season hurricane. Most producers who take proactive steps to conserve lines of capital and preserve cash, i.e., “hunker down,” will live to enjoy the rebound in prices and profits. However, if prices remain depressed for a longer period, as they did in the mid-1980s, there aren’t many viable options for highly leveraged producers but to seek a restructure or sale of their assets. Here’s hoping for a short storm season.
If you have any questions about this alert, please contact one of the lawyers listed below.
Buddy Clark 713.547.2077 [email protected] Theresa Einhorn 713.547.2078 [email protected] Jeff Nichols 713.547.2052 [email protected] Joseph A. Vilardo 713.547.2228 [email protected]