E&P Outlook

EP Outlook 1

A long, strange trip:

The status quo in exploration and production has re-emerged,

but not in the way we expected.

By Scott Cockerham

As an energy investment banker, it is always encouraging to meet with clients navigating the business as independent operators in exploration and production (E&P). The tech-savvy entrepreneurs who strike out on their own are the lifeblood of innovation in E&P, and it is their gumption that has led to breakthroughs in unconventional drilling, horizontal drilling and a host of other industry-advancing achievements.

However, the freedom to run your own business the way you see fit is counter-balanced by a lack of available capital. Independents are rarely diversified to an appreciable extent – although plenty of operators dabble in infrastructure and refining – and their fortunes are tied to the depleting nature of producing assets. Coupled with the high cost of hydraulic fracturing, today’s wells – even with the profit margins of service providers wiped out in the current downturn – make managing free cash flow a feat akin to juggling cotton balls in a wind tunnel.

In a sector where companies in a healthy market wink out and their assets are picked over like so much carrion, you may have expected smaller operators in the worst downturn in 30 years to fail en masse, with larger competitors just hitting minor speedbumps. It hasn’t turned out that way at all.

The Rich Get Richer

Upstream operating truly is a meritocracy. An independent oil and gas company invests in acreage, raw or producing, makes a bet on the appropriate bench, then tests that hypothesis. If a well proves the underlying economics of such an enterprise, the resultant drilling program is executed, all while the meter is running.

Combined with establishing a learning curve, an entrepreneur faces a million decisions of varying importance, the largest of which could mean his ruin. Even when a program is successful, the depletion of attendant reserves and cost of drilling means that in order to keep drilling, an oil and gas company will likely have to sell down its assets and/or take on investors and lenders. A small, independent operator is truly only as good as its last deal.

Available cash for capital expenditures is a good metric to highlight the plight smaller operators face. In comparing the EBITDA of operators to their CapEx in 2014, a high oil price environment, a picture emerges that is typical in E&P. Public cohorts, organized by enterprise value, strive to have their EBITDA exceed their CapEx. In other words, being EP Outlook 2above the 100 percent line is good: drilling programs, capital improvements and other forms of expansion can be funded from current cash flow, even if that means debt service. In 2014 only companies classified as “mega” (EV > $100 billion) outpaced their CapEx and, as you’d expect, those companies had the lowest cost of capital and greatest flexibility to execute drilling programs, regardless of size.

Medium and small operators (EV < $2 billion) worked at 67 percent and 69 percent of their CapEx, respectively. As an analog to a normal operating climate, 2014, despite the high oil prices seen that year, characterized capital availability by cohort fairly well. Smaller companies were in the most precarious position with regard to financial flexibility, but all but the mega companies’ drilling programs required extensive diligence to operate. The numbers may change over time, but in a high oil price market the descending slope of EBITDA/CapEx as the cohort EVs decrease is consistent.

Woe to Us All

The current downturn has been particularly cruel. Estimates vary, but new drilling programs have been shelved on a massive scale. 2015 saw the utilization of drilling rigs in the U.S. decline precipitously, and only in 2016 did that number start to rebound.

The first quarter of 2016 offered a snapshot of the despair U.S. E&P companies felt. When comparing EBITDA to CapEx in that quarter, all of the companies analyzed fell short. Large companies (EV between $2 billion and $15 billion) had EBITDA at 43 percent of their CapEx as a group, and medium companies (29 percent) were the hardest hit. The rash of bankruptcy filings that have occurred in the downturn corroborate the effects of that shortfall.

Companies could not afford to keep drilling, or even complete wells, in accordance with their programs and new programs were shelved to preserve capital. Markets for producing assets and unproduced acreage have until recently been moribund, creating a vicious climate for E&P companies. Cash flow declines as assets deplete under those conditions, and replacement operations simply cannot be undertaken.

The most telling result of this downturn is the mega cohort’s inability to provide EBITDA in excess of its CapEx early in 2016. By and large, those companies are highly diversified in less volatile segments of energy, yet they were severely constrained in their inability to replace reserves.

Shifts in cost of capital are also useful in determining the changes in financial health of companies. As credit ratings deteriorated in the downturn, investment grade debt issuances ground to a halt, and over $100 billion in institutional capital sat on the sidelines waiting for deployment. But, reserve-based lending, using the same enterprise valuation peer groupings as the EBITDA/CapEx comparison, from 2014 to the first quarter of 2016 only rose to 2.9 percent for mega companies. Small companies saw the largest jump from 5.7 to 7.8 percent.

Reserve based lending (RBL) doesn’t fund expansion on a large scale for E&P companies, but its effects on working capital are profound, particularly when issuers can’t access public markets. The decline in comparative EBITDA across the board likely signaled the suspension of new programs, and also a substantial decline in drilling in existing programs in 2015.

As U.S. rig count fell by 75 percent from December 2014 to the end of first-quarter 2016, according to Baker Hughes, working capital became precious to small companies. Given the precarious nature of small operators, RBL providers made the cost of capital for their product punitively high as the scope of RBL usage broadened.

While the mega companies’ EBITDA/CapEx ratio fell by 37 percent from 2014 to the first quarter of 2016, the small group only fell by 19 percent. Smaller operators set themselves up well as the year advanced.

Prepared to Succeed

From an EBITDA /CapEx standpoint, the first quarter of 2016 looks like the trough of the current downturn, and only with further hindsight will anyone know definitively. There are a host of reasons why that snapshot likely doesn’t match the low point of this market temporally, and no one measure should be used to make such a grandiose conclusion. Conversely, the second quarter of 2016 offered food for thought regarding how U.S. operators will perform as the downturn abates. It’s not a fulsome analysis, but it lends insight into how this dark chapter in the industry may end.

With regard to the EBITDA/CapEx view for the second quarter of 2016, public oil and gas companies seemed to crack

EP Outlook 3

the code. Aside from large companies subsisting at a paltry 39 percent, the other cohorts were in excess of 100 percent or close to it (the medium peer group lies at 84 percent). Most important, the small grouping (EV between $200 million and $500 million) sat at a commanding 199 percent while public operators with enterprise values below $200 million had a whopping 515 percent ratio.

Those figures are astounding. They are a credit to the fiscal discipline of some companies, long considered anathema to good upstream operators and the realm of nerds and institutional money that didn’t get how the industry “really works.” Debt was brought into line, lease operating costs and general and administrative expenses were trimmed, drilling timing and magnitude were meticulously monitored, planes were sold and hunting licenses lapsed. It’s a testament to the resilience of an industry that so many found a way to weather the market, especially for smaller entities that traditionally work at a capital availability disadvantage to their larger peers.

The good news of the second quarter of 2016 wasn’t all rosy, and the population of the cohorts declined since year-end 2014. Many operators went out of business, filed for bankruptcy or were delisted outright. The financial health of those companies obviously wasn’t very good, and they are the casualties of the downturn.

And We’re Back

By the end of the third quarter of 2016, the view of operators’ EBITDA/CapEx was actually healthier than 2014.  Bid-ask spreads for assets had narrowed and legitimate divestiture activity was occurring, leading to the correction in the U.S. upstream community that has shown it to be nothing if not versatile since the advent of unconventional drilling.  The four largest cohorts all sat above or near 100 percent (the medium group was at 98%) and the small group dropped to 73 percent from the previous quarter.

So, how did a wholesale uplift happen in a sub-$55 oil market? The third quarter of 2016 did see some high-profile bankruptcies, like Energy XXI, so some sick patients received care while out of circulation. While asset transactions did begin to occur increasingly in that quarter, those proceeds are often recorded below the EBITDA line on cash flow statements. But, larger companies limited their CapEx commitments for 2017 and 2018, contributing to a shrinking supply overhang and a buoying spot price for oil.  Conversely, smaller operators, which can be profitable and flexible at lower oil prices, took advantage of drilling held acreage, eating into EBITDA until those programs are self-sustaining.

For those oil and gas companies that remain, the future is bright. Institutional capital is re-entering the market, and the assets held by those that didn’t survive this downturn will pass to those capitalized to thrive when the price of oil fully rebounds. Drilling is resuming in earnest, but perhaps not at the levels seen in the heydays of 2014. U.S. operators are counting on better days ahead. They’re ready.

Scott Cockerham is an investment banker with Huron Transaction Advisory LLC, Huron’s broker dealer. He previously worked at Parkman Whaling LLC, Deutsche Bank AG and Goldman Sachs.


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