The capital-intensive nature of the upstream oil and gas sector, coupled with the recent and precipitous decline in commodity prices, has tightened financing markets for E&P companies and triggered a need for alternative sources of capital. At the same time, the credit profile of many independent E&P companies has become strained under substantial overleveraging. These distressed conditions provide opportunities for investors to develop creative solutions to satisfy E&P companies' liquidity needs. One creative solution that has received considerable attention is the drilling participation arrangement, commonly referred to as the "DrillCo" structure.
"DrillCo" deals have historically been bespoke, limited only by the collective imagination of the parties. However, within the last six months, common themes have developed with respect to key structural elements. "DrillCo" deals typically involve a commitment by the investor to fund an agreed share of capital costs to drill and complete wells in exchange for an undivided interest in the portion of the leasehold acreage required to produce from those wells (namely, a "wellbore" interest). Besides funding its respective ownership interest of drilling costs, the investor is also often required to fund a portion of the E&P company's share of drilling costs through a drilling "carry".
Once the investor achieves a stated return (measured on a cash-on-cash basis), the majority of its real property interest reverts to the operator. Of note, the investor's funding commitment is rarely a "blank check." Instead, investors either agree upfront to fund specific wells in a drilling program or, more typically, agree to technical and geologic parameters to limit the manner in which their funding dollars are utilized for an agreed period of time.
The "DrillCo" structure may be attractive to the operator as it allows the company to develop assets and add new cash flow streams with (i) no significant capital outlay and (ii) no additional balance sheet debt. Since the operator will be entitled to a larger percentage of future well proceeds, the structure may also provide operators with steady cash flows during a well's decline. From an investor's perspective, on the other hand, these deals can be attractive in that they permit (i) exposure to targeted shale basins, (ii) increased technical oversight (either through a development program or qualified well criteria) and (iii) collateral support beyond what is typical when investing in other portions of a company's capital structure.
There are a number of challenges faced by parties when negotiating a "DrillCo" deal. Three issues that we've seen derail otherwise economic transactions include: (i) commodity price protections, (ii) transfer restrictions and (iii) the investor oversight.
There is risk to the investor in a "DrillCo" deal that the operator will continue to spud wells in an uneconomic (or marginally economic) commodity price environment given the investor's drilling carry. Some early deals addressed this issue by including a commodity price "floor," which allowed the investor to temporarily suspend its funding commitment during periods of depressed pricing. Given the difficulty of setting an appropriate threshold in today's commodity price environment, a more common approach has been to shorten the investor's "commitment period." Although not a complete solution, investors also typically hedge a portion of expected production, and the investor may negotiate for realized hedge gains and losses to roll through the return calculation for purposes of reversion.
Restrictions placed on an investor's ability to exit the transaction and an operator's ability to monetize its assets may be another sticking point. Parties typically lock themselves into the deal for a minimum period of time (for example, during the period when wells are being completed). Restricting transfer during the drilling phase is particularly important for the investor in that the success of the investment may rely in large part on the operational expertise of its "DrillCo" counterpart.
Meanwhile, investors often need the ability to exit their investment within their funds' investment horizon. In this regard, one of the more complex issues is how to handle transfer prior to reversion. If the parties allow partial transfers prior to reversion (including through a tag sale), complex valuation issues often arise, including the process for forecasting reversion. The parties must also agree whether sale proceeds will flow through the return calculation, and, if not, whether the costs and proceeds for both the investor and the transferee are aggregated into a single return calculation. The operator may also negotiate for buyout rights that permit the operator to buy the investor's pre- and/or post-reversionary interest, usually for a multiple of invested capital (with a higher return hurdle than standard reversion).
While by no means a complete list, a final focal point is the scope of investor's governance rights over drilling operations. While the operator is generally weary of financial sponsors meddling in its business, in most deals, investors seek information-sharing rights more robust than customarily provided to non-operators, together with protection for operational cost overages through drilling cost caps (usually measured on a well group basis). As noted above, investor may also place technical parameters on permitted wells (for example, minimum lateral length, target formation and completion orientation) to ensure its capital is deployed to positive IRR wells. To the extent a well meets the agreed technical parameters, the investor typically must participate in funding that well, whereas investor may elect whether to participate in wells that fall outside of the parameters.
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