In the first quarter, signs of optimism seemed to surface after oil prices fell to near 13-year lows. The oil industry’s two biggest problems—oversupply and fears of weakening demand—are still with us, but demand appears relatively healthy and US shale and other producers have significantly reduced their capital spending. Meanwhile, global production by most estimates is expected to decline over the remainder of 2016.
In March, benchmark US West Texas Intermediate (WTI) crude-oil spot prices scored their largest monthly gain in almost a year, capping modest appreciation of 3.5% for the first quarter (to US$38.32 per barrel) even though supplies have accumulated steadily since mid-January and major oil-producing countries have yet to formalize a plan to maintain or reduce their output.1 International prices, as gauged by UK-based Brent crude oil futures, commanded a higher geopolitical risk premium than WTI and rose 6.2% in the first quarter, to just under US$40 per barrel.2 Speculation that the Organization of the Petroleum Exporting Countries (OPEC) would either cut or stabilize production levels to boost prices was a key reason for oil’s exceptional rally, as were ongoing producer spending reductions, US production declines (amid guidance for further declines in 2016), smaller stockpile builds, and a significant increase in US gasoline demand (up more than 6% since March 2015).3 These forces helped lift US crude oil prices 46% from a February 11 nadir of US$26.21 per barrel.4 The sharp rebound, like the plunge that preceded it, unnerved some traders and analysts, who said the moves were driven by expectations of improvement rather than an actual change in underlying supply and demand fundamentals. This view, in part, stemmed from a meeting in Doha, Qatar, on April 17 between OPEC heavyweight Saudi Arabia and non-OPEC producers, led by Russia, at which producers representing approximately 50% of world oil production discussed an agreement to “freeze” production in order to speed a recovery in oil prices. However, the meeting ended with little progress, as many expected, leaving the market to balance on its own, which seems well under way.
Overall, global crude-oil demand growth decelerated on a quarter-over-quarter basis, while worldwide supplies eased year-to-date through February.5 Total US oil production trended lower amid sustained rig-count reductions, and in late March stood at 9.04 million barrels a day (mb/d); when compared with a year earlier, that output has fallen by 384,000 b/d.6 Despite reduced output, overall US oil inventories reached a new record high of 534.8 mb in late March (+13.4% on a year-ago basis), even as a fall in the pace of imports drove a slowdown in inventory accumulation.7 Three months after the United States lifted a 40-year ban on oil exports, a growing volume of American crude oil has reached virtually every corner of the market, including France, Germany, the Netherlands, Israel, China and Panama, which could relieve pressure on domestic storage capacity.8
Further first-quarter support for oil prices came from unplanned production outages in places such as Nigeria, Iraq (Kurdistan) and United Arab Emirates, short covering and technical trading momentum, and expectations for stronger seasonal gasoline demand that, in turn, bolstered the demand outlook for oil. Currently, 2016 forecasts reflect potential record levels of gasoline demand in the United States.9 The global oil supply also appeared to be tighter than previously thought. According to the International Energy Agency (IEA), last year the tally of unaccounted-for oil grew to its highest level in 17 years, potentially implying that either demand was stronger than estimated, supply was weaker, or a combination of the two. This underscores how tracking oil is an imperfect science and how much the discrepancy can matter at a time when the issue of oversupply dominates the oil industry. Last year, approximately 800,000 b/d of estimated oversupply were unaccounted for in inventory data.10
In March, members of Franklin Equity Group’s Natural Resources research team, as well as energy and natural resources-focused investment professionals of Franklin Templeton Fixed Income Group, Templeton Equity Group, Templeton Emerging Markets Group and others, participated in one of the energy industry’s premier research gatherings. We had the opportunity to hear from chief executive officers and other top-level management representatives from energy companies around the world. Participating in these types of events is an important component of furthering the collaboration efforts of our global research teams. We gathered fresh insight on how companies were coping with the lower-price environment, what challenges they were facing, and what potential opportunities may be ahead. One broad takeaway we had was that US production resilience has been due, in part, to a shift toward markets with higher rig/well efficiency from low (i.e., Bakken to Permian shale-oil basins), and a focus on development options with the strongest economic return potential within each basin. This dynamic gave the impression that production was not responding to a declining rig count. Further efficiency gains in a price-recovery scenario will likely be offset by a reversal of this trend as producers step out from the “core of the core” and into higher-cost basins.
At this stage, we surmise there is likely little room for further efficiency gains in drilling time and cost savings, though production per well or the recovery rate (increasing the amount of oil that is recovered from each well vs. doing it quicker and at a lower cost) still has room for improvement. Meanwhile, in our view, gasoline demand looks to remain strong and distillate demand appears to be steady, while margins have improved from lows experienced earlier in the year. Our collaborative insights from others in the industry, in addition to our own in-house research, uncovered a few additional key themes we are watching.
Key Theme: Iran/Iraq Production
At present, aside from Iran and Iraq there are few sources of incremental supply to potentially hit the market in the near term, with the exception of a potential for increased volumes out of Libya. Increased production from either country could prolong the energy sector’s downturn. Iraq is believed to be “tapped out” due to reduced cash flow/spending and the need for a water-injection pipeline to significantly increase production, while Iran will require significant investment and time to reach its goals. Iran could be attractive to the “majors”—the world’s largest, diversified and integrated energy firms—if contract terms are better than those in Iraq, but that seems unlikely to us. Most analysts believe the country could add approximately 500,000 b/d in production before significant investment will be required, which is lower than current expectations and the country’s goal to grow production by 1 mb/d.
Key Theme: Strong Balance Sheets
As we see it, major integrated oil companies appear to be in a relatively strong position, given balance sheet flexibility and their potential ability to maintain or grow production in the face of significant capital expenditure reductions as long-cycle projects continue to come on line. The oil majors are also in a good position to acquire assets shaken out from the downturn and to increase spending on short-cycle projects in a recovery.
Key Theme: Exploration and Production (E&P) Spending and Cost-Cutting
Oilfield service companies have been focused on cutting capacity while maintaining the ability to respond to potential shifts in demand. With expectations for little recovery until 2017, we are seeing some early signs that demand may be improving somewhat.
Increased E&P spending has been a significant concern for investors who hold a general lack of conviction that companies will remain disciplined, even though they espouse a commitment to rationality. We believe the leg down in activity, when oil prices went below $30/barrel, likely will result in lower-than-anticipated oilfield revenues in the first quarter, with a likely negative impact to margins. Some management teams opined that the downturn in oil industry stocks has been emotionally driven by commodity price volatility, rather than driven by corporate fundamentals, which set the energy sector up for a strong recovery over the past couple weeks.
Most management teams we met with pointed to an oil price range of $50–$60/barrel as necessary for them to increase spending/budgets. Although, in some basins such as the Permian, the cost to extract a barrel of oil is lower than average due to higher initial oil flows and large expected recovery rates. We anticipate that prices would need to rise 15%–20% above $40/barrel to see significant increases in budgets and spending. In a recovery phase, bringing crews and rigs back into operation could take six to eight months. This task is made more difficult by the fact that overall energy sector E&P industry headcount has dropped significantly for some oilfield services companies from peak employment levels. E&P companies may initially focus more on balance-sheet repair than production growth, which could further delay any ramp-up of activity, and companies may be hesitant to increase spending from budgeted levels as a company’s production may not fully respond until 2017.
It is hard for us to see much more in the way of lower costs as the low-hanging fruit seems to have been harvested. Additionally, service costs may go up once drilling activity starts to pick up again, which could create a tailwind for oilfield services companies, but a headwind for E&Ps. E&P companies report being somewhat hesitant to pressure service companies for lower contract prices, given that many service companies already operating below cash-breakeven levels and producers want to ensure availability of service capacity and competition within the services industry when fundamentals begin to recover.
Key Theme: Tailwinds Offshore?
The consensus seems to be that deepwater development options are inferior to onshore unconventional resource development, including shale, which employs enhanced well drilling and completion techniques to produce previously uneconomic reserves. However, managements at integrated oil companies widely believe that deepwater oil operations can sufficiently compete with those in onshore US shale basins. Companies have conveyed that major project final investment decisions are likely to resume in 2017, after a hiatus the past two years as existing contracts expire and price deflation reaches its nadir. We think this should represent a tailwind for integrated oil companies in a recovery scenario. Many offshore projects are economically viable at current prices, host government terms are improving and bidding activity is relatively healthy. However, this activity has been constrained by a lack of cash, and actual contract awards have been very limited lately, though some management teams are seeing some signs of renewed urgency. Infill drilling—the addition of wells in an offshore field that utilize existing infrastructure “switched off” by the assessment of one company—and the pace of drilling these types of wells is now approximately 10 wells per year from 30 wells per year historically.
We continue to see potential opportunities in energy producers with low-cost resources, strong management teams, efficient operations and robust balance sheets. Although investors’ overall sentiment toward commodities and natural resources equities improved in the latter half of the first quarter, they seemed to generally remain skeptical that commodity markets were on the mend. We see this scenario as potentially laying the groundwork for further gains going forward. In our view, the recent volatility in sector stocks serves to highlight the importance of assessing intrinsic value and taking a selective, opportunistic approach to investing in the natural resources sector.
We view the macroeconomic picture as a primary risk for market rebalancing in 2016, but according to our analysis, announced budget reductions and expectations for production declines are combining with apparently resilient demand. This, we think, is signaling the potential for higher prices in the near-to-intermediate term.
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What Are the Risks?
All investments involve risks, including possible loss of principal. The value of investments can go down as well as up, and investors may not get back the full amount invested. Investing in a portfolio concentrating in the natural resources sector involves special risks, including increased susceptibility to adverse economic and regulatory developments affecting the sector. Smaller companies can be particularly sensitive to changes in economic conditions and have less certain growth prospects than larger, more established companies and can be volatile, especially over the short term. The portfolio may also invest in foreign companies, which involve special risks, including currency fluctuations and political uncertainty.