With most shale drillers funding operations with debt rather than cash flow, the U.S. shale boom is rapidly fading. Production growth has increased just 3% this year, after gaining 21% from 2017 to 2018 (EIA). Estimates for 2020 vary, but even the most optimistic forecast has the percentage of escalation much lower than during 2017–2018, causing many who ignited the revolution to express doubts. “You’re going to see a significant fall-back in Permian growth,” Scott Sheffield, CEO of Pioneer Natural Resources, told analysts in August. “You’ll probably move toward no growth for most people.”
Since the oil-price bust of 2014, unpredictability has been the theme of U.S. shale. But through all the down moments—a wave of bankruptcies and a drop in the number of drilling rigs—production has proven durable. Output grew by 2 MMbopd last year, but 2019 has been different. Even with prices holding steady above $52/bbl, oil output was virtually unchanged at 12.1 MMbpd in the first seven months, according to the EIA and API. In weekly data available since July, production has hovered around 12.4 MMbopd, but the increased output has come at a high price, especially for stockholders.
Investors have had enough. Despite record-high production, the investment community is demanding that companies spend less and pay more dividends. These actions have forced shale producers to file for bankruptcy or consolidate their positions with other producers to reduce competition. Bank funding is getting tighter, too, according to a Federal Reserve Bank of Dallas survey. Access to capital is especially vital to shale drillers because of the wells’ rapid decline rates. After the frac job, production falls by up to 70% in the first year, compared with as little as 5% from conventional vertical drilling. Hence, new wells must be drilled to maintain production. And once cash for drilling dries up, production will quickly follow. It’s all to do with “the change in investor mindset,” Sheffield said at a recent conference. “That’s probably taken about 300,000 barrels of oil a day off the marketplace going forward.”
Oversupply masking deficit. The boom in U.S. crude output, and ample supply from Russia and Saudi Arabia, are concealing a major issue festering in our industry. Conventional oil and gas discoveries during the past three years are at their lowest levels in 70 years, and a significant rebound is not expected, according to a report by IHS Markit. The low levels in discoveries are a result of a dramatic decline in wildcat drilling during the past 10 years in conventional oil and gas plays—most drastically after oil prices collapsed in 2014. The report also states that these trends have far-reaching implications that could limit future conventional reserves additions.
Underinvestment in conventionals. The decline in conventional discoveries was driven primarily by competition from short-cycle-time unconventional projects, and financial investors who questioned long-term, high-cost, frontier projects, the report said. These factors, in turn, shifted drilling away from areas where potential discoveries could be larger, and reduced upstream exploration investment, due to concerns about long-term oil demand. “One of the main drivers is the shift of investment by U.S. independents from international exploration to shale opportunities in the U.S.—shorter cycle-time projects—with greater flexibility to respond to changing market conditions,” said Keith King, IHS Markit. “These operators can quickly stop an unconventional project if oil prices fall.”
Beyond the overall reduction in drilling for conventional reservoirs, the report also identified additional reasons for the modest reserve discoveries in recent years. One of the most telling is that the average discovery size of conventional fields varies greatly with the maturity of the basins being explored. Basins that are in the frontier and emerging phases have average discovery sizes 10 times greater than average discovery sizes made in more mature basins. The average discovery size of these early life-cycle basins is approximately 210 MM bbl versus 25 MM bbl from mature basins discovered during the last 10 years.
Replacement ratio lowest in recent history. The energy replacement ratio for conventional resources stands at approximately 16%, which is the lowest in recent history. This means that only one bbl out of every six consumed is being replaced by new sources. This is the lowest replacement ratio we have seen in the last two decades, according to a senior analyst.
Sweet spot. However, the industry has high hopes after the prolific success of ExxonMobil’s Stabroek Block off the coast of Guyana, which has led to a surge in offshore exploration in the Caribbean. More acreage is being made available for bidding, with some countries conducting their first-ever licensing rounds in 2019 and 2020. Offshore drilling activity has been increasing in recent years, with 23 new exploration wells expected in 2019. But there’s a caveat.
High costs, low oil prices undermining offshore profitability. Despite the larger discovery size associated with these deeper-water and frontier/emerging basins, operators are drilling fewer wells in these areas. In 2014, 161 new field wildcats were drilled in deep and ultra-deep water; by 2018 that number dropped to 68 wells (IHS Markit). Drilling in frontier/emerging-phase basins declined by a similar amount. And some international E&P companies are struggling to make money from offshore investments made during the latest investment upturn.
In the current risk-averse environment, the industry prefers drilling in mature basins, near existing infrastructure, where operators can bring projects online in two to three years. “The industry will likely continue to invest more in less-costly, less-risky, quicker cycle-time onshore projects and shelf, with deepwater investment remaining constrained,” King concluded. “There will be areas of intense activity in deep water and, in emerging-phase basins as well, but overall, these regions will only see incremental gains.”
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