As an investment banker, choosing a financing structure to fit a client’s capital needs was fairly straightforward. The challenge came from working with parties to communicate the benefits and ties of a funding mechanism.

Now that I’m with an operator, however, the focus has shifted away from acquiring capital. Far more attention is paid to how financing structures affect operations, how repeatable they are and their effects on profitability beyond distributions to investors.


There aren’t enough villages

Much ink has been spilled (and tears shed) over the status quo that successful, albeit smaller, operators face with regard to free cash flow. They operate at a substantial deficit to projected capital expenditures and must either divest assets or seek outside funding to finance drilling programs. While costs of capital for reserve-based lending and syndicated debt remain extremely affordable (see Costs Of Capital chart), those channels may not be sufficient to bridge a program to self-sustaining production.

Financial sponsors like mezzanine lenders and private equity are well equipped to fill such a funding gap. Private equity’s cost of capital is always misleading: it’s simply a target return a sponsor pursues on behalf of its investors. But programs with desired rates of return below 25% to 30% could have a difficult time attracting private-equity funds’attention.

Mezzanine lending costs of capital are also misleading, but for a much different reason. While the discount rate of a mezzanine note may seem affordable (10% to 15%), there are other costs that creep in: paid-in-kind financing,origination discounts (the due diligence costs undertaken by the lender) and rights and warrants applied to a financing package. The cost of capital of these bells and whistles can raise the aggregate to 25%.

An operator may look at these options and determine that a relationship fairly close to autonomy is appropriate, and the upside of these financing structures is significant. But there is a trade-off to such arrangements.

By and large that drilling program is the sole focus of an operator, and flexibility beyond a drawn and agreed-upon AMI is nonexistent. For a three-year program, an exploration and production (E&P) company’s course is charted. Additionally, for those going the mezzanine lending route, companies must be cognizant that these facilities are designed to reach profitability for the lender first, not allow the borrower to pay back the debt at the earliest opportunity. Operators who perform well within these parameters are few and far between, and it’s no surprise that those who can deliver have serial forays with their sponsors.

Also of note is that while financial sponsors have successfully raised enormous sums of capital over the past few years, the amount still pales in comparison to aggregate onshore drilling demand, and those funds are invested over a multiyear period (see Fundraising chart).

Financial sponsors can only participate in so many opportunities with E&P companies. An optimist would say that leaves the door open to pursue capital as one’s own sponsor. That’s true, but it comes with ties that extend far beyond an offering’s structure.

The tail that wags the dog

Regulation D (Reg D) transactions have long existed to allow issuers to offer private investors exposure to drilling programs without registering with the SEC. Provided offerings have fewer than 35 nonaccredited investors and 2,000 investors in total, an issuer can raise as much as it needs. In and of itself, the structure seems simple. The investors targeted within the Reg D mechanism, however, have profound effects on the issuer.

The vast majority of investors in a Reg D offering must be, at the very least, accredited investors. If those investors are not institutional, that is to say private individuals or retail investors, they are a large population and tax sensitive. They are limited in the amount they invest in an E&P private placement by virtue of the small percentage real assets take in their investment portfolios. Accredited investors are drawn to oil and gas placements by issuers who surrender their rights to initial intangible drilling costs (IDCs), a mechanism by which limited partners (LPs) are able to deduct a large part of their investments from their taxable incomes. The act of providing IDCs fundamentally changes how the issuer operates.

First, investment capital must be put to work in a very short period of time in order to maximize the LPs’ IDCs and give them their highest total return. Realistically, that means that a partnership drills all of its wells within a year. Second, given that LPs who receive IDCs invest smaller amounts than institutional investors, the size of the offerings is limited.

Most importantly, one-year programs must perform, by definition, without temporal diversification. The drilling program for a specified year is determined prior to a partnership closing and deviations are minimal, where underlying commodity prices could have profound effects on investment returns. In order to maximize returns for LPs, an operator must assume a development drilling mindset, similar to an MLP.

Thus, truly exploratory or play-proving work must be undertaken on the company’s balance sheet or in another investment vehicle. For most E&Ps, changing to a retail-friendly operational profile would require substantial modifications to deal evaluation, staffing, operational oversight and accounting controls. Thankfully, these programs usually have no associated debt service.

Accredited investor private placements come with a high cost of capital because the costs of syndication and sales are similarly large. Aside from the fixed costs of printing, shipping and legal work, an issuer must pay a placement agent that effectively wholesales to the registered investment advisors (RIAs) and broker dealers (BDs) who sell to the LPs. Sales commissions are pricey and account for the bulk of costs. Additional costs and efforts like investor accounting, reporting (K-1s), servicing and BD due diligence are also significant.

How can an operator reduce the cost of an offering for its LPs? It can reduce the cost of sales by creating a BD that wholesales or even sells directly to investors. Creating a BD is not an easy task, as it must meet SEC and Financial Industry Regulatory Authority (FINRA) regulations. It’s a wholly separate business from drilling wells and requires diligent work by a well-trained staff. Even with the creation of a BD that passes muster with regulators, syndication costs can’t go too much lower: internal commissioned sales staff have a market for which they’re compensated. Similarly, external sales staff have expectations for commissions to keep an operator’s offering at top of mind.

Should a retail-oriented issuer wish to raise money from institutional investors, there is an ample pool of interested LPs available. However, they look for focus of effort for the duration of their investments and occasionally look at accredited investor programs as a distraction. Ridgewood Energy executed a $1.1 billion institutional raise in 2014 after a long track record in retail fundraising.

Whether the company will continue to be able to syndicate to accredited investors remains to be seen.

Class it up

A successful operator with a long-standing track record does have the ability to reach out directly to institutional investors. The benefits of moving to larger investors are clear when compared to accredited investor partnerships: more exploratory drilling programs, less frequent fundraising, lower costs of capital and fewer LP relationships to manage. Such a raise would likely still occur under Reg D.

No matter how distinguished its tenure, though, an E&P company must come to terms with the fact that it will be perceived as a first- time fund, resulting in an extended length of time for fundraising (perhaps longer than a year), lower fees charged as a sponsor both in terms of management fees and carry, and higher costs for a placement agent. Along with going it alone for a raise, an issuer usually has to beef up internal controls for accounting; hire accounting, controlling and investor relations staff; and communicate regularly with investors in addition to periodic reports.

The good news is that it gets easier for operators after they raise their first fund. Hires and procedures are in place, management and incentive fees can come up to market levels, relationships have been established with investors, and placement fees eventually abate.

It’s a painful process initially, but once the bandage is ripped off an operator can focus on drilling wells.

Conclusion

For decades, operators have sought counsel from advisers from the viewpoint that all they needed was capital to drill out programs they’d blocked and tackled. As financing mechanisms have solidified, the truth has become more apparent. Rarely, if ever, is a financing solution tailor-made for an E&P. Operators who seek complementary relationships with investors may have to change drilling program characteristics, make hires, adhere to new regulatory requirements and alter reporting procedures.

Scott Cockerham is vice president of business development at U.S. Energy Development Corp. He was formerly a partner at Parkman Whaling LLC and has worked at Deutsche Bank and Goldman Sachs.

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