Part of an ongoing Managing The Cycle series

We often forget our lessons of the past. One such memory lapse currently seems to be the full-cycle, cascading impact of declining crude oil prices and its effects on the E&P and services sectors. Since the formation of OPEC, we’ve seen at least four such periods.

The first question is, “Why so repetitious?” That answer is comparatively simple—oil and gas are commodities, and all commodities are cyclical. In the 1983 comedic film, “Trading Places,” a wonderful throwaway line came when the Duke brothers, calling a turn in the commodity market and gloating over their ability to set a direction for prices, simply said, “Mr. Valentine has set the price.” For the oil and gas industry, Mr. Valentine is the group of OPEC price doves: Saudi Arabia, the United Arab Emirates and Kuwait.

OPEC is bifurcated, based on country-specific agendas, between price hawks and price doves. Price hawks have significantly lower levels of oil export revenue per capita: for example, Venezuela, Iran, Algeria, Nigeria and Iraq. For price hawks, the higher the price, the more economic support for their struggling economies. In this group there is no spare capacity, as they produce flat out.

In contrast, price doves have far higher oil export revenues per capita. Their surplus of spare and immediately available production capacity gives them the advantage of being the “price-maker” rather than the “price-taker.” As OPEC’s price-makers, price doves focus on two objectives: maintaining long-term demand and, concurrently, maintaining their share of the global oil export market. Today, the price doves are once more exerting their prowess in dictating the market-clearing price by refusing to cut production.

Why? In an environment of rising prices, economic demand slows. More non-OPEC crude comes to market as the economic clearing price rises, and other non-OPEC producers bring on new production that, consequent to higher prices and new technologies, expands the economically accessible resource base. The most recent example is the shale oil production surge in the U.S.

Domestically, crude oil prices have declined 50% from their recent highs to a posted WTI price of about $50 per barrel (prices had dropped to $50 at press time). Actual postings by crude oil purchasers in the field are lower. For example, sour crude in the Bakken oil shale play at the time of a $67 WTI posting was quoted at $40.58 per barrel and in the South Texas Eagle Ford trend, the comparable price was $49.75 per barrel, both substantial discounts.

The second shoe

Market chatter is focusing on declines in commodity price per se. After all, it is a substantial and rapid decline. However, many seem unprepared for the second shoe that will drop. As was the case in 1986-1987, the price contagion spillover may prove profound and debilitating to both the E&P and services sectors of the industry.

Extreme proved reserve value compression and attendant bank defaults have set the stage for a massive reinvention of business models and capital structures, drastic cuts in 2015 capex, and a future focus on more-economic opportunities outside of shale reserves.

For the industry, the timing could not be worse. For most public companies and their associated lenders, Dec. 31, 2014, was “report card time.” Under SEC Regulation SX and FASB Opinion 69, there are strictly defined standards for gauging proven reserve values. The downdraft affects far more than wellhead prices. There is the attendant extreme margin compression that accompanies already expended costs. Under SX and 69, public companies are required to use average wellhead prices and costs for the year as of Dec. 31 and held flat for the future.

The immediate results are:

Wellhead prices at year-end are assumed to never reverse. Moreover, as prices remain low in 2015, the average price used to calculate year-end values will continue to decline. Result: a significant loss in calculated future net revenues.

Operating costs are held flat at year-end actuals. Likely, these would be trimmed in the industry downturn with price cutting and more internal efficiencies. However, under FASB 69, none of these reductions may be included. As forecasted production declines, once wells reach the point that net cash flow after operating costs is negative, no additional cash flows or reserves are allowed on the FASB 69 disclosures. Result: a potentially significant loss in the quantities of proved producing reserves permitted to be booked.

Capital costs are also based on year-end actuals. Thus, if prices hold in the range of even $50 to $60 per barrel, the full-cycle economics cause some previously deemed proven undeveloped wells to become uneconomic. The regulations force an illogical hypothetical decision in the disclosures, to drill for $50 per barrel oil with a cost structure that was designed for $100 oil. Result: A significant number of development locations are deemed uneconomic and not permitted to be included in reported year-end reserves.

Impairments. GAAP accounting imposes an annual “ceiling test.” GAAP states that reserves are carried at the lower of either cost or FASB 69 reserve values. The significant decreases in reserve values occasioned by the first three factors referenced here will likely force significant year-end write-downs. Result: In extreme cases, the auditor’s going concern opinion may become qualified.

The cumulative effect of these factors will depend to a large extent on the mix of producing vs.undeveloped reserves. For many companies focused on the shales, this 40% or more reduction in wellhead prices could translate to an 80% reduction in reserve values. Consequently, for publicly listed companies, equity values may decrease even more than the already debilitating decline in net reserve values.

Clearly, the evaporation of reserve values to be disclosed by public companies will render raising common equity extremely problematic. Investor sentiment is turning decidedly negative, reflecting the sharp decline in oil prices in the past two quarters.

More troubling in 2015 will be the annual redetermination of borrowing bases by lenders. Lenders typically use price decks that are already stressed cases, meaning, below current prices. Now, even these are being ratcheted down significantly. Hedging activities may mitigate some of the dramatically diminished net asset values, but they will not be able to make up for reserve volume cuts occasioned by Regulation SX disclosures.

In short, the die has been cast and there is no way out of the consequences. How will these effects cascade down to E&Ps, particularly those levered up in the shale plays?

First, the same processes outlined above will take place with all lenders, whether they be traditional senior secured lenders or mezzanine providers. Many companies will find themselves in a hard default with their lenders. A borrowing base that had 50% availability six months ago may well be redetermined down to a value that is now under water with bank requirements.

Second, underwater borrowers will have little choice but to sell properties to reduce debt. Equity and debt markets will be largely closed. The price fetched for such assets will need to exceed the calculated borrowing base of the specific property. Lenders will block the sale of properties at prices that do not reduce the hard default of the new borrowing base.

Opportunities ahead

In this industry paradigm shift, is there an opportunity to buy “while the blood is spilling in the streets”? The answer is yes. But it is time to get back to basics. In doing so, the execution of bottom fishing will need to be highly disciplined, with a strong technical knowledge of the specific field.

Out of adversity springs opportunity. In that regard, there are at least three areas that are worth considering:

Conventional nonstrategic properties. As distressed companies seek to deleverage, the first candidates for monetization may be the more traditional, higher-margin conventional properties. In the case of shale properties, significant expended lease costs, drilling obligations and the belief that prices will rebound in the near term signal attempts to preserve those strategic investments and dispose of nonstrategic conventional properties. Given an organization’s recent focus on more aggressive shale oil development, these conventional properties may not have had the attention they would otherwise deserve.

In executing this strategy, consider partnering with a basin-specific operator. The value-creation proposition is based on the knowledge base and integrity of the local operator. A properly structured joint venture could include mutually agreed upon budgeting, co-investment, appropriate buy-sell agreements, and incentive-based additional compensation to the operations partner that supplements well overhead recoupments.

Other low-cost conventional opportunities. Recent initiatives undertaken by the government of Mexico will shortly open up that country to foreign investment. A plethora of plays will be offered this coming year, including conventional underexploited properties, deepwater projects and various shale plays. (Proceed with caution!) The economic attractiveness of these larger capex endeavors will depend on concession terms and up-front bonuses. Otherwise, the same economic considerations that exist in the U.S. also exist south of the border, plus foreign investment risks. For the smaller independent willing to absorb the risk of a foreign investment, smaller underexploited conventional fields are prime candidates.

Natural gas bias. An orphan commodity of the past five years in many basins, natural gas has been degraded to become the necessary stepchild that comes with drilling for high NGL reserves in shale trends. High initial production rates in those basins are followed by steep, hyperbolic declines. Notwithstanding that balloon in drilling, however, natural gas storage remains below the five-year average.

As NGL prices decline alongside oil, natural gas production capacity will continue to fall as reduced drilling fails to make up for those steep hyperbolic declines. In a rising price environment, there are likely to be attractive opportunities in conventional natural gas properties.

An overreaching factor in these opportunities will be the matriculation of various recovery technologies to smaller conventional deposits. For example, with advances in downhole tools, it is now possible to implement lateral drilling at intervals as shallow as 2,000 feet, due to decreased turning radiuses. The considerable R&D dollars spent on these technologies by state-of-the-art service firms such as Halliburton, Schlumberger and others will migrate to new applications in more conventional reservoirs.

An omnipresent wild card lies in the increasingly disparate agendas of two well-militarized forces in the Persian Gulf—Saudi Arabia (predominately Sunni) and Iran (predominately Shia). Exacerbating the growing animosity between Sunnis and Shias is the control of oil pricing by Sunni-dominated Saudi Arabia. The zones of friction are there and growing. Time will tell how internal differences and disparate agendas of price doves and price hawks will sort themselves out.

In the meantime, one would be well-advised to recognize the coming cascade effect of lower oil prices and, at the same time, step back and reexamine the opportunities peeking out from the clouds of adversity.

Over his 35-year energy industry career, Mark Harrington has served as founder and/or high C-level executive of seven separate private-equity groups, public and private exploration companies and oil service entities. He currently advises two privately held companies.

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