Houston — Second-quarter 2019 was a cautious quarter for US upstream operators, and little change is expected in the second half of the year apart from the Permian Basin in the Q3 and Q4, as companies stick to their knitting, improve their financial and operational performance and grow production at a modest clip.
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Q2 2019 for upstream operators was characterized by uncertainty on several fronts but particularly over oil prices as rig counts dropped and companies continued to devote more cash to shareholders and focus on financial targets.
Here are likely themes of Q2 2019 conference calls that will begin in mid-July, as oil price volatility lodges at top of mind for oil company executives:
OIL PRICE VOLATILITY
Coming at midyear, Q2 is an important quarter when producers typically review market fundamentals and sometimes tweak activity levels and capital budgets if oil prices change notably. But WTI oil dropped below $50/b in Q4 2018, and again fell last month to near $50/b after rallying to the mid-$60s/b in April.
That has left operators cautious and likely to maintain their original budget and activity levels rolled out early in 2019, experts say.
Even as WTI has risen to a relatively comfortable level in the high $50s, oil companies still appear haunted by "the threat of sub $50 jitters," Rob Thummel, managing director for Tortoise Capital Advisors, said.
With relatively stable prices and OPEC/Russia's agreement to extend 1.2 million b/d of production cuts through March 2020, status quo is largely the watchword for the rest of the year -- and possibly into 2020.
Anecdotal evidence of flattening upstream activity abounds. Among the recent chatter: exploration-and-production companies are spacing out work programs so they don't experience steep activity declines by year-end as capital expenditures dwindle. As a result, well completions may soften in the next few months and further weaken in Q4.
For producers to stray from their earlier-set 2019 capital budgets, there would have to be a major swing in oil prices, analysts say.
As long as oil remains in the current $50/b-$60/b range, "we don't expect any sort of big pickup in activity in 2020," Philip Dollar, an analyst with Wells Fargo, said.
The Permian Basin may be an exception to otherwise flat activity as new pipeline takeaway is schedules to come online starting in Q3 from the West Texas/New Mexico play to US Gulf Coast refining and export markets, analyst Matt Andre, of S&P Global Platts Analytics, said.
"We're actually expecting rigs to pick back up in the Permian in the second half of this year as takeaway becomes largely unconstrained through new pipe capacity" of 2 million b/d (for oil) and 2 Bcf/d (for natural gas), Andre said.
On Thursday, Wells Fargo cut its Lower-48 drilling and completion spending and activity outlook for 2020 to flat from 8%-10% previously. The bank said it expects not only less spending also but a "softer" second-half 2019 stage count. (Stages are intervals between fractures. More stages expose more oil and gas and provide potentially higher well yields).
Apart from supply growth concerns, the investment bank cited growing uncertainty over global demand -- a widely noted industry issue -- and indications by its upstream and oilfield services coverage teams that a "downshift" in L48 spending is needed to keep oil markets balanced.
STICKING TO FINANCIAL, OPERATIONAL GOALS
CEOs appear to be unequivocally sticking to their financial and operational goals set earlier in the year.
In June analyst conferences, E&P executives touted a continuing push to whittle down costs, improve well yields, provide higher margins and cash flows and reward shareholders while still growing production in some cases by double-digit percentages year on year.
Another common theme during recent executive presentations was capital spending based on a $50/b oil price or even less for the next few years.
"We feel that being a 1x levered company [i.e., having a debt/EBITDA ratio of 1] at a mid-$40s/b oil price is where you need to be, simply due to all the volatility in our business," Jack Harper, Concho Resources president, said in late June webcast remarks at the JP Morgan 2019 Energy Conference in New York. EBITDA is earnings before interest, taxes, depreciation and amortization.
During the 2015-2016 industry downturn, many highly levered companies had much higher multiples -- sometimes 6x, 7x or even more times debt/EBITDA. That put them at risk of defaulting on financial obligations to lenders.
Pre-2014, banks had recommended a 5x debt/EBITDA ratio but during the downturn reduced that to 3.5x. More recently, many E&P executives have set their debt/EBITDA ratios lower, and 1.5x to 2x is not uncommon.
"A lot of this [multiple austerities and efficiencies being touted] is that companies are worried about the downside risk which is still there" for oil prices, James Williams, president of energy consultants WTRG Economics, said.
Also, recent poor stock E&P performance has caused CEOs to devote more attention to shareholders by raising dividends or buying back shares.
"It's clear to operators that if they are going to get investors back in the sector, the way to do that is to [focus on their goals]," operationally and financially, Thummel said.
-- Starr Spencer, email@example.com
-- Edited by Valarie Jackson, firstname.lastname@example.org