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The oil price slump that started in July 2014 took the North American oil industry by surprise, even though the underlying reason was simple: too much supply, not enough demand. With the benefit of hindsight, the signs of oversupply and an impending oil price adjustment were hiding in plain sight, but we failed to pay attention.
Again with the benefit of hindsight, the 4.4 million barrel per day (MMbbl/d) increase in North American oil production from 2008 to 2015 now looks like a classic monetary bubble: The EIA estimates that more than $1.2 trillion was invested in the development of North American unconventional oil fields from 2005 to 2014, of which about $500 billion was new outside capital. Unfortunately for E&P companies, at least 60% of the new capital raised was debt, and a significant percentage was invested in high-cost reserves that cannot be economically developed at current oil prices. As a result, the North American E&P sector is highly leveraged, with shrinking asset values to make matters worse.
With the passage of enough time, the supply/demand imbalance will correct itself, and oil prices will recover. Supply will shrink as producing wells decline and because capital providers have closed their wallets, forcing the E&P industry to cut capital spending. Demand will pick up because lower oil prices will stimulate higher consumption of refined products, and economic growth in Asia and North America will continue.
Now that we have (probably) reached the bottom of the price slump, it is critical that we avoid repeating the same mistake in reverse, i.e., ignore the signs of recovery. E&P companies and investors need to start thinking about what the upturn will look like and how they should position themselves to capitalize on the most likely price scenario.
Assuming that global oil production and demand trends continue on their recent paths, the following projections for the recovery should be fairly accurate:
• 2016 will mark the bottom of the oil price collapse;
• supply and demand will be in balance by first-quarter 2017;
• oil prices will be capped at $50 to $60/bbl through 2020; and
• the recovery will be a “winner-take-all” environment.
These projections are not dependent on an output cut by OPEC. While the recent “output freeze” discussions between OPEC and Russia have boosted oil prices by up to $5/bbl, the reality is that OPEC’s and Russia’s production are at all-time highs. An eventual OPEC/Russian output cut cannot be ruled out entirely, but it would require months of negotiations to establish enforcement mechanisms, and the cuts would be from a very high baseline.
Let’s look at these projections in more detail.
1. Oil prices reached a bottom in first-quarter 2016, at approximately $26/bbl, which is also the “shut-in” price level for many vertical wells. Even though the U.S. oil markets were still over-supplied, oil prices couldn’t descend below the mid-$20s as it was still profitable to store crude, and there was enough crude oil storage capacity to absorb excess production. There is a risk that crude storage will reach max capacity by late summer 2016, in which case the fall refinery turnarounds could briefly force the oil price to retest the spring lows and possibly even slip below well shut-in prices for vertical stripper wells.
The “floor” for oil prices is the “shut-in” price level below which producers would lose money by producing their wells. The shut-in price level varies significantly from well to well, based on production volume, location, grade of crude and artificial lift technology. If prices drop below $25/bbl, most U.S. vertical stripper production would be shut in. Below $20/bbl, horizontal wells that have been producing for longer than three years and are in their terminal decline would start to be shut in. Below $15/bbl, horizontal wells between 18 months and three years old would start to be shut in. And so on.
As long as it is still profitable to put oil and refined products into storage and there is storage capacity available, oil prices will not go below the $25/bbl shut-in price level.
Recent EIA publications indicate that as of February 2016, the U.S. still had over 100 MMbbl of crude working storage capacity available. In addition, approximately 12 to 20 MMbbl of new storage capacity is being built.
Making the following assumptions about the U.S. crude oil market in 2016:
• imports increase 0.5 MMbbl/d (7.3 to 7.8 MMbbl/d);
• production falls 0.6 MMbbl/d (9.2 to 8.6 MMbbl/d); and
• demand rises 0.25 MMbbl/d (from 19.4 to 19.65 MMbbl/d).
There will be sufficient working storage capacity to absorb all of the 2016 over-production. The caveat is that storage will be extremely full, probably close to 95% capacity! This leaves a very small margin for error, and even a modest shift in production, imports or demand growth could materially expand the stock build so that working storage ends the summer at 100% capacity. If this happens, there is a definite risk that the fall refinery outages could trigger a price drop below the $25/bbl shut-in price for vertical stripper wells, resulting in shut-ins of some producing wells for a short period.
2. Global oil supply and demand will be in balance by first-quarter 2017, based on rapid reductions in U.S. oil production in 2016 and 2017 and more than 1 MMbbl/d annual demand growth. OPEC will not agree to cut production, because OPEC policy has become another battleground in the sectarian proxy war between Saudi Arabia and Iran. Iranian production will increase 1 MMbbl/d by year-end 2017.
OPEC oil production is likely to pick up in 2016 and 2017, even though this runs counter to its interest in a rapid price recovery. The growth is driven by the geopolitical competition between Saudi Arabia and Iran, rather than by economics, and is evidenced by the rig count: according to Baker Hughes’ worldwide rig count as of early May, the Middle East is the only region globally where rig count has been stable over the last 18 months, rather than declining. Iran is trying to regain market share now that international sanctions have been lifted, and a reasonable forecast for Iranian production growth is 1 MMbbl/d by the end of 2017. Saudi Arabia’s strategy is to balance its geopolitical and economic goals, so it will augment output and market share enough to limit Iran’s market share growth, but without driving the oil price lower. Although Saudi Arabia has the capacity to ramp up production by up to 2 MMbbl/d, doing so would probably cause oil prices to drop below $20/bbl and result in too much economic pain to justify the geopolitical gain in its conflicts with Iran.
Russia’s oil production is difficult to forecast, as it is the only major oil producer with drilling costs that are based in its local currency, rather than in dollars or Euros. The 50% dive in the ruble against the dollar since mid-2014 has softened the impact of the dip in oil prices on Russian oil companies, as the ruble value of a barrel of oil has only slid by 25%. Consequently, Russia’s oil output probably won’t slow and will presumably remain at about 10 MMbbl/d.
Non-OPEC global oil production is inclined to decrease by 2% to 3% in 2016 and 2017, from 32 MMbbl/d to 30.5 MMbbl/d. Low oil prices have starved E&P companies of cash for drilling and reduced the availability of credit. Most international oil companies, whether government-controlled or independent, will focus their capital expenditures on maintaining existing production through workovers and optimizing artificial lift.
U.S. oil production will recede by about 0.6 MMbbl/d in 2016 and over 1 MMbb/d in 2017, because drilling activity has plummeted. The U.S. oil-directed rig count skidded below 400 in March 2016, with further falls likely, as the large independent E&P companies that dominate the most productive U.S. oil fields (i.e., Permian, Eagle Ford, Bakken) have cut capex by 50% to 80%. In addition, mature oil wells have natural declines of 5% to 10% p.a., while shale wells fall off 50% to 85% in the first 12 to 24 months after initial peak production. Bucking the trend, eight to 10 deep Gulf of Mexico wells are expected to come online in 2016.
Global oil demand rose by approximately 1.54 MMbbl/d in 2015, according to the February OPEC monthly oil market report, stimulated by the sag in oil prices. Global economic growth is projected to stall in 2016 and 2017, so oil demand growth will also be lower, probably closer to 1 MMbbl/d.
Assuming that OPEC’s fourth-quarter 2015 estimate of global oversupply of 1.67 MMbbl/d is accurate, the net effect of the production and demand changes is that the two will be in balance by first-quarter 2017. Although it could happen as early as fourth-quarter 2016, recent experience indicates that oil production is much more prone to exceed projections than to come in below.
3. Oil prices will stay in a range of $30/bbl- $45/bbl in 2016, before climbing toward $50/bbl-$60/bbl in 2017. Prices will be capped at $50/bbl-$60/bbl in the medium-term, because there is an abundance of oil that can be sold out of storage, or that can be economically produced by OPEC or U.S. shale drillers at prices above $50/bbl.
There is no “right” price for oil. It is set by the short-term decisions of buyers and sellers, who are influenced by the market’s perception of surplus or scarcity. From mid-2014 to December 2015, the market clearly felt that there was a large surplus of crude oil, and WTI prices collapsed from $107/bbl to $26/bbl.
The oil market is currently in a “trading” phase, without clear fundamentals to drive the price higher or lower. That means that throughout 2016 the oil price will be volatile, but should remain within a range of $30 to $45 (unless crude storage reaches max capacity, as discussed in #1).
The global oil supply/demand fundamentals will be back in balance by early 2017, which will be the signal for a recovery in the crude price to $50/bbl-$60/bbl by late 2017. This is likely to be the “cap” on oil prices for the next three to five years, as the oil markets will be in a state of abundance. Any spike in oil prices will immediately result in sales of oil out of storage, a surge in OPEC exports or an acceleration of U.S. shale oil drilling and/or completion of pre-drilled wells. There is just too much crude economically available at $50/bbl- $60/bbl for the market to support a higher price.
It is critical to understand that the U.S. will exit 2016 with about 600 MMbbl of crude oil in commercial storage (excluding the SPR), as well as some 800 MMbbl of refined products. The “normal” level of commercial crude storage for the U.S. is about 300 MMbbl, so the remaining 300 MMbbl is available to be sold at very short notice if oil prices spike.
The oil storage glut is also not just restricted to the U.S., it is a global phenomenon. OECD and China crude oil storage is estimated to peak at 2.1 billion barrels (Bbbl) in early 2017. It could easily take until the end of 2018 for crude and products storage to return to normal levels globally.
4. The recovery will be a “winner-take-all” environment. E&P companies with the highest-quality “A” reserves will be able to produce economically at prices below $50/bbl, e.g., the core areas of the major shale plays. By contrast, companies with “B-quality” reserves, will struggle to earn a competitive rate of return on drilling. Capital will be tighter and more expensive than it was from 2010 to 2014 and will flow primarily to producers with the highest IRR wells. E&P companies that cannot attract outside capital will have to drill out of net cash flow.
From 2005 to 2014 the U.S. E&P sector attracted more than $500 billion of private and public capital, including first-lien debt. With oil prices averaging $80 and very low interest rates, almost every unconventional play in North America could generate returns significantly above the cost of capital.
The 65% collapse in oil prices since third-quarter 2014 has drastically curtailed access to capital for the E&P sector, significantly increased the cost of debt capital and made any oil prospect with finding and development (F&D) costs above $15/bbl uneconomic to drill.
With oil prices projected to stay at or below $60/bbl, E&P companies will need to achieve gross finding and development costs of $10/bbl -$15/bbl to attract outside capital to drill new wells. (A crude oil price of $50/bbl only generates net revenue of $33/bbl, after (i) 20% royalty, (ii) 6% taxes, (iii) $3/bbl gathering/ transportation and (iv) $50/bbl LOE and overhead. A well with an EUR of 400,000 bbl of oil that cost $5 million to drill and complete would generate a 2.7x ROI.) Good operators in the core areas of the Permian, Eagle Ford and Bakken trends can drill and complete wells between $7/bbl and $10/bbl, generating IRRs greater than 35% at WTI prices between $50/bbl and $55/bbl.
New private equity and public equity capital will seek out the highest rates of return. This means the majority of new capital will flow to E&P companies with “A” quality acreage in the core areas of the Permian, Eagle Ford or Bakken (or in other plays with comparable economics). E&P companies with “B” quality acreage, i.e., F&D costs higher than $15/bbl, will find attracting new equity capital challenging. Their drilling budgets will have to be funded out of net cash flow and/or revolving credit lines, limiting their rate of growth.
This is exactly the scenario that has played out in the U.S. natural gas sector since 2012. Between June 2011 and April 2012, Henry Hub prices collapsed by 63%, from $4.92/MMBtu to $1.82/MMBtu. The gas-directed rig count fell from a 2011 peak of 936 rigs to 624 rigs in April 2012. But even though gas prices recovered to average $3.73/MMBtu in 2013 and $4.37/MMBtu in 2014, the rig count kept contracting, reaching a new low of 101 rigs in February 2016.
The reason for this is simple: gas producers in the Marcellus, Utica and Haynesville basins were able to consistently enhance well EURs and trim drilling costs, to the point that other gas formations could not compete. Gas-directed rigs outside the Marcellus, Utica and Haynesville basins have dropped 93% since 2011, and there are now more gas-directed rigs running in the Marcellus, Utica and Haynesville than the rest of the onshore U.S., according to Baker Hughes’ rig count as of the middle of April.
The future looks very similar for the U.S. oil sector, as those E&P companies with the highest-quality acreage will entice the capital to drill new wells and grow production and profits. This higher level of drilling activity will also drive continued cost efficiencies and economies of scale. The rest of the industry will have far less access to capital and therefore will remain on a lower-growth trajectory for an extended period, until either oil prices rise, or costs decline.
No easy recovery
What this all means is that many E&P companies will find the recovery almost as tough as the slump. There are concrete steps, however, that E&P companies can take today to position themselves to survive the recovery. The overall goal of these steps is to re-position their asset profile to higher-profitability, lower-risk reserves, concentrate lease footprints on the best acreage and maximize capital preservation:
• divest assets that cannot earn a competitive rate of return at $50/bbl;
• re-deploy capital into higher-return prospects, including through acquisition;
• re-evaluate geology and petrophysical models for undeveloped prospects and delineate core areas with the most favorable economics;
• let go of leases on acreage outside the core areas and only acquire new leases if there is capital to drill them during the initial lease term;
• re-evaluate completion designs to optimize stimulated rock volume and proppant placement in the primary pay zone;
• focus drilling on “exploitation” and not “exploration”, i.e., lower-risk, higher certainty of result; and
• hedge at least 75% of oil production for 24 to 36 months out, including projected new production from new wells.
These steps are designed to reverse the legacy of the “land grab first, drill second and science last” strategy that was prevalent in the U.S. E&P sector between 2010 and 2014. While the land-grab strategy may have been justifiable in a very competitive landscape, with high oil prices and ready access to capital, it has left many E&P companies with bloated land inventories and exposure to too many plays.
Concentrating on a single or limited number of core prospects allows E&P companies to devote the resources required to develop and integrate a comprehensive technical understanding of the geology, geophysics, petro-physics, completion and wellbore design. With very few exceptions, the rock properties of unconventional resource plays can differ greatly over short distances, and a “one-size-fits-all” approach to drilling and especially to completion will result in sub-optimal well results.
Capital preservation is also a critical factor in an environment where new outside capital is limited and expensive. Drilling “exploitation” wells is a key aspect of that, i.e., allocating the majority of capital to drill proved undeveloped wells, rather than possible wells. The other key aspect is that E&P companies need to be more aggressive in protecting their cashflow from oil price volatility by increasing the volume and term of their hedges. Drilling oil wells already carries an incredibly high level of geologic and mechanical risk and uncertainty, there is no need to add price risk on top of that.
In conclusion, the new oil world order will undoubtedly be a tough place to survive, but the U.S. E&P industry is extremely resilient and innovative. E&P companies that successfully transition from the “boom” mentality to a single-minded focus on reducing cost and risk, while increasing EURs, will survive and thrive.
Mark Miles, MBA, LLB, has 25 years of experience in the energy sector, including in E&P, power, pipelines, renewables, transmission and trading. He was president and COO of Riley Exploration Group from 2012 to 2015, where he helped grow the company from a start-up to a $250 million valuation and supervised the leasing, development and operation of projects in the East Eagle Ford Shale and Taylor Sand. Previously he was a managing director at Pritchard Capital, partner at K Road Power, principal at AIG Highstar Capital, vice president at Azurix Corp. and director at Enron Capital & Trade.
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