U.S. energy consumption, production, and exports reach record highs in 2018

U.S. energy consumption, production, and exports reach record highs in 2018


The United States produced a record amount of energy from various sources in 2018, reaching 96 quadrillion British thermal units (quads), an 8% increase from 2017. This increase in production outpaced the 4% increase in U.S. energy consumption, which also reached a record high of 101 quads. At the same time, U.S. energy exports increased 18% to a record high of 21 quads in 2018, reducing net energy imports into the United States to a 54-year low of 4 quads, or less than 4% of U.S. energy consumption.

U.S. primary energy production by source
Source: U.S. Energy Information Administration, Monthly Energy Review

In 2018, crude oil and natural gas accounted for 57% of all U.S. energy production, with crude oil production seeing an increase of 17% and natural gas an increase of 12% from 2017. Natural gas plant liquids production also increased by 14%. Energy production from renewable energy increased 4% from 2017, mostly because of growth in solar (22%), wind (8%), and biomass energy (2%). Nuclear electric power production remained virtually unchanged in 2018. Coal was the only energy production source to decrease in 2018, falling 2% from 2017 levels.

Total U.S. consumption of energy also increased from 2017 levels but at a slower pace than production. Compared with other fuels, petroleum had the largest gap between growth in production and growth in consumption in 2018. The 17% increase in crude oil production outpaced a modest 2% increase in total domestic petroleum consumption, resulting in a 73% increase in exports of crude oil and a 6% increase in exports of petroleum products in 2018 compared with 2017.

U.S. primary energy exports by source
Source: U.S. Energy Information Administration, Monthly Energy Review
Note: Other includes coal coke, biomass, and electricity.

Exports of crude oil and petroleum products made up 68% of all U.S. energy exports in 2018, accounting for most of the increase in total U.S. energy exports from 2017. Petroleum product exports reached a record-high 10.2 quads, or 5.6 million barrels per day. Crude oil exports nearly doubled and reached a record-high 4.2 quads (2 million barrels per day), surpassing both coal and natural gas on an energy equivalent basis to become the second-highest U.S. energy export. Exports of natural gas and biomass energy (e.g., ethanol) also reached new records in 2018, and coal exports reached its highest level since 2013.

U.S. primary energy net trade by source
Source: U.S. Energy Information Administration, Monthly Energy Review
Note: Other includes coal coke, biomass, and electricity.

In 2018, U.S. energy imports decreased 2% compared with 2017, which, along with record-high energy exports, brought combined net U.S. energy imports to their lowest levels since 1964. In 2018, the United States was a net exporter of coal, coal coke, petroleum products, natural gas, and biomass energy. The United States remained a net importer of crude oil, which has been true for every year since 1944. However, in 2018, net imports of crude oil reached its lowest level since 1991.


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2018 was likely the most profitable year for U.S. oil producers since 2013

Net income for 43 U.S. oil producers totaled $28 billion in 2018, a five-year high. Based on net income, 2018 was the most profitable year for these U.S. oil producers since 2013, despite crude oil prices that were lower in 2018 than in 2013 on an annual average basis.

Lower production costs per barrel of oil equivalent (BOE) and increased production levels contributed to a higher return on equity for these companies for the fourth quarter of 2018 than in any quarter from 2013 through 2018.

The companies included in the analysis are listed on U.S. stock exchanges, and as public companies, they must submit financial reports to the U.S. Securities and Exchange Commission. EIA calculates that these companies accounted for about one-third of total U.S. crude oil and natural gas liquids production in the fourth quarter of 2018. However, these companies were not selected as a statistically representative sample but instead because their results are publically available. Their results do not necessarily represent the U.S. oil production industry as a whole.


Source: U.S. Energy Information Administration, based on Evaluate Energy

Most of these companies operate in Lower 48 U.S. onshore basins, with some in the Federal Offshore Gulf of Mexico and Alaska, and some in several other regions across the globe. Because of various corporate mergers and acquisitions in 2018, the number of U.S. producers that EIA examined in this analysis fell from 46 companies in 2017 to 43 companies in 2018.

The aggregated income statements for these 43 companies reveal a trend of relatively low increases in expenses directly related to upstream production in 2018. Although these upstream production expenses per barrel typically correlate with crude oil prices, the magnitude of these increases in 2018 was small compared with the increase in prices.

The annual average West Texas Intermediate (WTI) crude oil price increased 28% from 2017 to average $65 per barrel (b) in 2018, but expenses directly related to upstream production activities increased 16% between 2017 and 2018 to $24/BOE. When including depreciation, impairments, and other costs not directly related to upstream production, expenses for these 43 companies averaged $48/BOE in 2018, the lowest amount from 2013 to 2018.

In contrast to production expenses, between 2017 and 2018, upstream revenue for these 43 companies increased 31% to average $48/BOE in 2018, mainly because of the increases in average energy prices and production. As crude oil prices fell in late 2018, their upstream revenue declined 11% between the third and fourth quarters of 2018.


Source: U.S. Energy Information Administration, based on Evaluate Energy

However, this group of companies reported financially hedging nearly one-third of their fourth-quarter 2018 production at prices in the mid-$50/b range, offsetting revenue declines when WTI prices fell lower than $50/b by the end of the year. Consequently, even with their decline in upstream revenue in the last quarter of 2018, total revenue increased for these 43 companies because of the gains from financial derivatives.

Contributions to revenue from derivative hedges—which increase in value when prices decline—for these 43 companies reached the largest total for any quarter since the fourth quarter of 2014. Financial hedging can act like an insurance policy, reducing risk by stabilizing revenue for producers. When oil prices fall lower than the prices at which producers established a hedge, the producer effectively receives higher revenues than selling at market prices. When oil prices rise higher than the hedged price, hedging results in a loss that is treated as an operating expense.
Source: EIA

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U.S. exploration and production companies (E&Ps) are tapping the brakes on their capital spending in 2019 after two years of strong investment growth and a return to profitability that in 2018 approached the level generated in the $100+/bbl crude oil price environment back in 2014. The pull-back in capex this year appears likely to slow the pace of production growth, and comes despite a 30% rebound in crude oil prices in the first quarter of 2019. What’s going on? Well, many investors remain skeptical about E&Ps, as evidenced by stock prices that remain in the doldrums, and to gain favor with investors, a number of E&Ps are returning cash to them in the form of share buybacks and higher dividends. Today, we consider the current state of investment in the E&P sector, how it’s affected by stock valuations and how it affects production growth.

In a number of blogs over the past three years, we’ve documented the dramatic recovery of the E&P sector from the financial crisis caused by the plunge in oil prices that began in late 2014. Through portfolio high-grading and an intense focus on operational efficiency, the 44 representative E&Ps we track demonstrated that they could grow reserves and increase production on lower capital budgets. The nearly 50% reduction in “finding and development” costs (the cost of “finding” an additional barrel through organic capital spending), excluding acquisitions — from $15.01/boe (barrel of oil equivalent) in 2014 to $8.41/boe in 2018 — helped the E&P sector roar back to profitability last year. Our universe of 44 E&Ps on average netted a healthy pre-tax operating profit of $11.03/boe in 2018, which compares with a barely breakeven profit of $0.07/boe in 2017 and is only 20% below the profit generated by the group in the $100+/bbl environment in 2014. And with first-quarter 2019 oil prices rising 30% — the largest quarterly rise since 2009 — the E&P sector appears to be in a position to report continued profit growth this year.


E&P share prices by December 2018 had plunged 40% from their September highs when crude prices slid to $45/bbl, and despite the subsequent oil price rebound, share prices have recovered less than half of their late-2018 declines.

Several oil companies released slimmed-down 2019 capital budgets in late 2018, when oil prices were still sagging. Many industry observers assumed the planned declines in investment reflected conservatism about the oil pricing outlook going forward. The oil price decline turned out to be short-lived, however, with prices recovering strongly starting in late December 2018 and through the first quarter of 2019. Still, updated capex plans released with year-end 2018 results in late January and February continued to mirror the overall trend, and almost no companies moved to revise their budgets upward. (Guidance updates released so far with first-quarter results in late April and early May do not indicate any significant changes from year-end forecasts.)

Figure 1 shows that capital spending for our universe of 44 E&Ps (blue bars, left axis) totaled $135 billion in 2014, but was cut by more than $50 billion in 2015, then slashed in half in 2016 to $40 billion. In 2017, capital outlays rebounded with commodity prices, increasing by about 50% to about $63 billion, and rose by another $15 billion or so in 2018. This $77 billion in 2018 investment generated a 26% increase in pre-tax operating cash flow to $112 billion last year (orange bar to right; left axis) and a 7% increase in production (gray line; right axis). Historically, the higher cash flow would have led to continuing capital investment increases in 2019.  However,  as shown in Figure 1, the companies in our universe announced a collective 12% retrenchment in capital outlays this year. Three-quarters of the 44 E&Ps we track will cut capital spending in 2019, with a median decline of 15%.


Figure 1. E&Ps’ Cash Flow, Capital Spending and Production, 2014-19. Source: Oil & Gas Financial Analytics, LLC (Click to Enlarge)

So, what gives? The E&Ps’ year-end results revealed a major driver of the lower capital budgets: a significant boost in the amount of cash flow being returned to shareholders, primarily through share repurchases. The buyback programs of our group of 44 E&Ps — which are designed to appeal to investors — soared from $4.7 billion in 2017 to $15.6 billion in 2018, while dividends increased 17% to $6.7 billion.

The reduced 2019 capital spending will have an impact on oil and gas output. The surge in investment over the past couple of years drove a substantial 7% increase in production in 2018, including a 13% increase by our Oil-Weighted Peer Group. 2019 guidance indicates oil and gas production growth by our 44 E&Ps will moderate to only 5% this year, or a 200-MMboe rise to 4.7 billion boe. Capital allocation across producing regions in 2019 remains virtually the same as in 2018. The Permian Basin will see the lion’s share of capital investment this year, at 42% of total capital spending. The Eagle Ford Shale is a distant second at 11% of 2019 capex, with the remaining capital investment spread among the Bakken (9%), the Marcellus (8%), International (8%), SCOOP/STACK (6%), the Denver-Julesburg (D-J) Basin (5%), the Utica (2.5%), and the offshore Gulf of Mexico (2%). Next, we review 2019 capital spending and the impact on production by peer group.

Oil-Weighted E&Ps

Figure 2 shows that the 18 E&Ps in the Oil-Weighted Peer Group collectively reduced their 2019 capital budgets by 12%, or $4 billion, to just under $30 billion (blue bar to far right; left axis) despite generating $19 billion in pre-tax operating profit and $45 billion in cash flow in 2018 (orange bar to right; left axis). Capital outlays peaked in 2014 at $47 billion (blue bar to far left), and were slashed by $19 billion in 2015 and by an additional 45% in 2016 to $15.6 billion. In 2017-18, capital spending rebounded along with oil prices, increasing by 60% (to $25 billion) in 2017 and by another 34% (to $34 billion) in 2018. The oil-weighted E&Ps spent $5 billion on share repurchases last year, $3.8 billion more than they did in 2017 and 23% more than in 2014. Dividends paid in 2018 by the oil-focused E&Ps reached $3.6 billion in 2018, 20% higher than in 2017 and on par with 2014 payouts.





Finding and development costs for the oil-weighted E&Ps have fallen from more than $21/boe in 2014 to $12.72/boe in 2018. This allowed the producers to generate 13% production growth in 2018 (gray line, right axis) despite investment that was 30% lower than in 2014. Output growth is expected to slow to 7%, or about 100 MMboe, in 2019. Over 60% of the capital invested by the Oil-Weighted Peer Group this year will be spent in the Permian Basin, in line with the 2018 capital allocation, while 13% will be invested in the Eagle Ford (2% ahead of last year), 9% will be spent in the Bakken and 6% will be spent in the D-J Basin

Oil-Weighted E&Ps' 2018 Profits, Cash Flow, Upstream Spending and Capital Returned to Shareholders

Wednesday, 05/08/2019Published by: jeremy








Diversified E&Ps

Figure 3 shows that the 16 E&Ps in the Diversified Peer Group are collectively forecasting an 11% decline in capital investment to $29 billion in 2019 (blue bar to far right; left axis) despite generating more than $50 billion in cash flow in 2018 (orange bar to right; left axis). Capital spending for the Diversified E&Ps peaked at $70 billion in 2014 (blue bar to far left), and was slashed by nearly three-quarters by 2016 to $18 billion — the companies were undergoing earth-shattering changes to become profitable in a low oil and gas price environment. These changes included more than 3 billion boe in asset sales in order to reposition themselves by divesting non-core assets. In 2016, capital investment started to rebound, increasing by nearly $9 billion in 2017 and then adding another $6 billion in capital outlays in 2018. A portion of the $21 billion in free cash flow last year was used to increase payout to investors. In 2018, the Diversified E&Ps repurchased nearly $8.4 billion in common shares, nearly three times the amount bought in 2017. Dividend payments last year increased modestly to $2.7 billion, but that was still about 50% lower than what was paid out in 2014 as companies clearly have a preference for opportunistic share repurchases.  



Fueling the rise in free cash flow has been a sharp reduction in finding and development costs, which has enabled companies to lighten up their capital commitments while still maintaining reserve and production levels. Finding and development costs have been cut by more than half, from nearly $24/boe in 2014 to $9.24/boe in 2018. While the Diversified Peer Group’s production (gray line, right axis) has been hampered in recent years by the large divestment of assets, the downtrend appears ready to make a turnaround. In 2018, production posted its first increase since 2015, growing nearly 2% in 2018 to 1.8 billion boe, and it is expected to grow another 4.5% in 2019 to nearly 1.9 billion boe.  

About 40% of the Diversified E&Ps’ capital budgets will be invested in the Permian Basin, with 16% allocated outside of the U.S. The Bakken will absorb another 13%, compared with 9% last year. The SCOOP/STACK and Eagle Ford are each taking on 10% of peer group capex, similar to last year’s capital allocation.



Gas-Weighted E&Ps

Capital investment for the 10 E&Ps in the Gas-Weighted Peer Group has followed a slightly different trend than the rest of our E&P universe. Capital spending by these gas-focused companies peaked in 2014 at just over $17 billion (blue bar to far left in Figure 4; left axis) and subsequently fell by more than 60% to its 2016 bottom of $6.7 billion. Capex rebounded in 2017 by nearly 90% to $11 billion, but stagnated in 2018 before an expected 16% decline this year.  

The gas-weighted E&Ps have also reduced capital costs, but not to the same extent as the other peer groups. Finding and development costs fell by only about 20% between the $4.52/boe posted in 2014 and the $3.75/boe reported in 2018. Nevertheless, free cash flow has increased sharply over the past few years, as have share repurchases, which are up seven-fold to $2.2 billion in 2018 — multiples of what was repurchased in the 2014-17 period. Dividends in 2018 amounted to $306 million, nearly 20% higher than in 2017, but still well below the 2014 payouts. As shown in Figure 4, production for the Gas-Weighted Peer Group has risen steadily, from 819 MMboe in 2014 to 1.261 billion boe in 2018, a compounded annual growth rate of 9.5%. The rate of change is expected to slow precipitously in 2019, to only 1.8%, resulting in 2019 production of 1.284 billion boe.


Figure 4. Gas-Weighted E&Ps’ Cash Flow, Capital Spending and Production 2014-19. Source: Oil & Gas Financial Analytics, LLC (Click to Enlarge)

Three-quarters of the gas-weighted E&Ps’ 2019 investment will target Appalachia (60% Marcellus, 15% Utica), which is on par with 2018. An additional 7% is being invested in the Eagle Ford and another 4% being deployed in SCOOP/STACK.

While crude oil prices got off to a slow start in 2019, the ensuing rally looks like it will push E&Ps’ first-quarter 2019 profits to exceed fourth-quarter 2018 results and set the stage for a strong 2019 as a whole.  We will continue to monitor E&P announcements and will provide an update at mid-year to highlight any changes in capital spending, production and capital allocation trends we spot. 

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