Guest post by Isuru Seneviratne, Founder & Portfolio Manager, Radiant Value Management. Isuru has specialized in energy sector analysis and investing since 2004. Visit www.radiantval.com for more information on the author and firm.
We expect oil to hit an inflection point around 3Q16, when inventory drawdowns push the market to consider forward-looking, half-cycle costs of production (above $60/bbl). Lacking a regulator with spare capacity, the lagged effects on supply from unprecedented capex cuts will drive prices much higher by the end of the decade. Here we build upon our analysis from September 2015, Breaking Point: Capitalizing an Oil Glut, and its Consequences to discuss the market tightness exacerbated by increasingly frequent supply disruptions and characterize an investment that combines low-cost base value with leverage to rising prices.
The Elephant Not in the Room
Advances in technology had opened up previously inaccessible resources in countries outside OPEC. Saudi Arabia, after years of regulating prices, changed course and opened the spigots to drive down rival production. Non-OPEC production did not decline, and Saudi Arabia, Iraq, Iran and Kuwait all invested to increase market share. The year was 1985, and the ensuing slump outlasted 10 years – oil’s ‘lost decade.’
Exhibit 1: Adapted from Welcome Back to Boom-Bust Oil Prices – Robert McNally Source: EIA, BP, St. Louis Fed, ExxonMobil, The Rapidan Group and Radiant Value Management
Similarly today, Saudi Arabia is striving to curb high-cost production both inside and outside OPEC, inducing a generational reset in energy.
“The producers of these high-cost barrels must… lower their costs, borrow cash or liquidate.” Saudi oil minister Naimi: Oil production cuts won’t happen (February 2016).
With all producers competing aggressively for market share, some analysts and market participants have proclaimed that oversupply will lead to another decade of low prices. However, in 1985, OPEC spare capacity was 10 million barrels per day (mnb/d), or 17% of global consumption, compared to 1-2 mnb/d (sub-2% of consumption) today (see Exhibit 1). Spare capacity is defined as developed fields being withheld from the market, to be ‘swung’ online in short order to maintain oil prices and economic stability during unanticipated disruptions. Maintaining spare capacity requires a willingness to surrender substantial market share over a sustained period in response to structural oversupply, a costly role no one wants to play today.
The Lessons from Kuwait
Nearly 7,000 Kuwaiti oil workers (out of ~20,000 locals and expatriates employed by the industry) went on strike between 17 and 20 April. Disruptions in Kuwait came as a surprise to the oil world, which was fixated on a simultaneous summit in Doha, Qatar, where Russian, Mexican and OPEC leaders had gathered to discuss a ‘production freeze’ to stabilize the market. Such a move would have been purely symbolic since Saudi and Russian production levels (10.2 and 11.0 mnb/d respectively) were already plateauing and the only country capable of growing production, Iran (with 3.3 mnb/d), was adamant on restoring output to pre-nuclear sanction levels. While Doha talks failed due to this sticking point, production loss from the Kuwaiti strike (1.7 mnb/d initially) surpassed the global supply surplus (recently revised down to 1.3 mnb/d for 1H16 by the International Energy Agency), exposing the fundamental tightness of the market. Pressured by low oil prices, Kuwait, the fourth-largest OPEC producer, is pursuing public sector salary reforms. But the three-day strike ended with the oil workers being excluded from any such move. Kuwait brings to focus an industry operating with such a thin cushion. Due to economic hardships faced by producers, both field reinvestment and infrastructure security is degrading. This, in turn, has increased the frequency and/or length of unplanned outages due to sabotage, strikes, political unrest and fires. Raymond James estimates global unplanned supply outages (excluding Iran and Libya) are almost 1.8 mnb/d in February 2016 (1.9% of global demand) led by Nigeria, Iraq, Syria and Yemen, nearly 2.5x the lows of February 2015.
Regulating a Wild Industry
The loss of OPEC as the ‘central bank’ regulating oil markets is akin to the breakup of Standard Oil Trust in 1911, which ushered in a cycle of boom and bust (Exhibit 2). For most of the history of petroleum, different entities have attempted to regulate oil supply in order to stabilize prices. Neither industry nor governments enjoy volatility in a commodity essential to modern civilization. The first such regulator, the Standard Oil under John D. Rockefeller, entered upstream exploration and production (E&P) only after monopolizing refining and integrating with pipeline and railroad companies. Following the discovery of East Texas oilfield in 1930, the Texas Railroad Commission started to enforce strict production rationing. The most successful era of oil regulation followed under the Interstate Oil Compact Commission. The major international oil companies, ‘The Seven Sisters,’ helped by withholding supply from the massive Middle Eastern concessions they operated. This period saw the lowest oil price volatility despite large disruptions of the Iranian nationalization (1951), the Suez Crisis (1956-1957), and the Six-Day War (1967); and elevated demand during WWII. OPEC became the oil regulator in the early 1970’s but has succeeded in this role only when Saudi Arabia acted as ‘swing producer,’ bearing the brunt of supply cuts or increasing output to balance the market.
OPEC began to lose its grip on the market nearly 10 years ago when spare capacity reached unusually low levels (see Exhibit 1). The ‘core OPEC’ of Kuwait, Qatar, UAE and Saudi Arabia joined to curtail supply in 2009 only as an emergency measure during the global financial crisis. While Saudi technocrats are well aware of the importance spare capacity, they are reluctance to lose market share by swinging alone. “Saudi Arabia is willing to use its capacity to moderate the price. Not as a swing producer – and I want to clarify and emphasize that. We are not in the business of being swing producer.” Oil Minister Ali Al-Naimi in 2000, OPEC’s Caracas Summit Seeks Stable And Fair Prices, Closer Dialogue With Consumers.
To paraphrase Robert McNally, “Brent oil price spike to $146/bbl in 2008 showed that OPEC could not impose a ceiling on prices, and the collapse since 2014 demonstrates that OPEC would not put a floor on prices.”
Barrels Follow Investment Flows, but with a Lag
Exhibit 3: Previously sanctioned projects continue to draw capital and deliver production
Source: Rystad Energy New York Presentation, 13 April 20167
E&P is a capital-intensive industry. Without continuous spend, oil fields naturally decline at an average rate of 10-12% per year. Sustaining capital reduces this rate to 5-7% on most fields. At major development projects, especially offshore and oil sands, production comes online only 4-5 years after development initiation (or ‘sanction’). Exhibits 3 shows how large capital projects sanctioned during the years of $100+/bbl oil will continue to come online over the next few years, notwithstanding prevailing low prices.
Rystad Energy estimates that E&P capex was down $220 bn (-24%) year-over-year in 2015 and estimates show a further $145 bn (-21%) cut in 2016 (Exhibit 4). Declines are catching up, driving net production down, led by the U.S., Mexico, Colombia, China and the U.K. Despite a deep devaluation, Russia may be hard pressed to maintain its current production, which has approached peak-Soviet levels. On the other hand, annual consumption growth has been tracking the 1.2 mnb/d (+1.5%) expectation for 2016. Barring a global economic collapse that dampens demand, we expect an inflection point in 3Q16, when oil will need to be drawn from storage. At this point, the market would start to recognize the half-cycle costs for production, which includes drilling, completion and operating costs, but excludes land acquisition, well tie-in and infrastructure costs. North American shale production could remain flat through to 2020 at $60/bbl, exploiting the highest quality acreage with the best equipment operated by the top crews. But as production declines in the rest of the world accelerate, much higher cost barrels will be needed to fill the growing gap towards the end of the decade. The E&P industry was all too familiar with this pattern of boom-and-bust a century ago but may have since forgotten.
Exhibit 4: The recent capex cuts have been the most severe (in real terms) on record.
Source: Rystad Energy New York Presentation, 13 April 2016
Safety plus Leverage
At Radiant, we seek low-cost E&P investments with superior upside profile to a rising commodity, trading at a discount. We are accumulating equity of such a North American producer at ~7% its 2010 IPO price. With largely the same share count as at IPO, today the equity is priced below $400 mn. Over the last 2-3 years, the company has undergone a systemic board and management overhaul as it transitioned from an over-promising, free-spending resource acquirer to a tight-lipped, disciplined project executor. A major project developed between 2012 and 2015 may take decades to recover the ~$750 mn invested, hurting investor confidence. However, the capital spend is complete and production is ramping up over 2016. As more barrels are produced over the same fixed cost, this project will switch from being a cash consumer to a generator. Operational risks are low as the company overcapitalized the asset to ensure performance. Production will remain flat for 5-7 years at sustainable breakeven costs of ~$45/bbl. For 2017 we conservatively model ~$35 mn project free cash flow at $60/bbl WTI oil against corporate G&A of ~$20m.
While the aforementioned project will contribute 2/3 of 2017 production, the rest of the business can recycle the resultant cash flow at high rates of return. The company spent over a billion dollars since 2010 to secure large and contiguous land positions in two under-developed shale resources. While the resources have proven to be top quartile with a strategic infrastructural advantage, the company was unable capitalize development due to the commodity rout. In early 2016, a large and successful independent E&P company committed to farm into these plays by spending ~$700 mn over the next 5 years. With the independent’s technical expertise from a similar basin, low-cost production from this business segment will see aggressive growth. Our company has the flexibility to pursue opportunities as cash flows and economics warrant.
An upfront cash component of the deal helps our company repay and refinance debt due near term. At an average WTI oil price of $42/bbl for 2016, our calculations show year-end net-debt to be ~$65 mn, a comfortable ~4% of equity. Deal-based value for the shale resource minus pro-forma net debt exceeds half a billion dollars. Thus the market ascribes a negative value of ~$100 mn to the above-mentioned project despite having proved, developed and producing reserves for 12 years.
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This material contains certain forward-looking statements and projections regarding the performance of certain projects and markets. These projections are included for illustrative purposes only, are inherently speculative as they relate to future events, and may not be realized as described. These forward-looking statements will not be updated in future.
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