The fourth quarter upstream earnings season raised multiple issues in the
oil patch. But the biggest theme was really a single, solid dilemma: can
E&P operators hit their production growth targets, and still maintain the
fiscal austerity they had pledged last year, in the face of rapidly
rising oilfield service costs?

Analysts generally think so. WTI oil prices that have risen from a
2015-2017 average of $48/b to roughly $60/b have buoyed the industry and
settled a blanket of confidence over oil company boardrooms.

Low prices had stemmed from a rapid rise in shale oil output, which added
nearly 4 million b/d of crude from end-2010 to end-2014 when falling oil
prices kicked off a prolonged industry downturn. The event caught
upstream companies, long used to outspending their incomes, off-guard.

Now that industry is well into recovery mode, most observers believe the
painful recent past has made a deep impression that won’t easily be

“I haven’t come across anything that says [producers] won’t continue to
operate within cash flows” which was a recurrent oil company management
promise in late 2017, Sami Yahya, senior analyst at S&P Global Platts
Analytics, said. “They’ve said they don’t want to overspend and my
impression is if that seems like it might happen, they may cap activity

Not only will operators almost universally try to spend within their cash
flows, but higher oil prices have now resulted in excess, or “free” cash
flows for many oil companies. Others will achieve that status this year
or in 2019.


While excess cash flows will be spent on mending balance sheets or
returning cash to shareholders via higher dividends and share buybacks,
rig count additions will likely be “modest” this year, according to a
Platts Analytics review of tight oil operators released last week.

Platts Analytics expects 100 more active rigs in the fleet this year than
the 650 that stood at year-end 2017. By contrast, E&P operators added 273
rigs last year.

Even with relatively few rig adds, many of the biggest independent
producers expect their production to rise by double-digits this year.
Platts found 13 of 16 large independent producers have guided to 2018
production increases of 12% to 40%, including ConocoPhillips, Concho
Resources and EOG Resources.

In Q4 2017, crude and condensate production from US shale jumped 14% to
5.3 million b/d from the prior quarter. That was driven by “accelerated”
completions, particularly in the Permian Basin of West Texas/New Mexico,
Platts Analytics indicated.

While completions of previously drilled but unfinished wells – which are
popularly known as DUCs – were slow for most of 2017, new well tie-ins
picked up near year-end. That accounted for the rise in oil production by
about 650,000 b/d in Q4, the Platts Analytics review said.

As year-end 2017 neared and crude prices headed toward the
psychologically important $60/b level, confidence was running so high
that several oil and gas companies provided Wall Street with not just a
single year of guidance, as is customary, but three years, from 2018 to

For example, E&Ps Noble Energy, Devon Energy and Concho Resources, all
stated they believed they could sustain growth levels for total
production, oil production, or both, in the double-digits during that

Their confidence came from drilling results in 2017 — where drilling
longer horizontal well legs, using more proppant to keep well fractures
open, and better “landing” of the drill bit in the choicest parts of
subsurface zones has gradually lifted per-well oil volumes in recent

Throughout the 2015-2016 downturn oil companies became expert at driving
more and more oil from the ground at increasingly lower costs — a knack
which keeps improving.

In fact, even though oilfield service and equipment costs are expected to
rise 7%-15% this year, which the Platts Analytics review believes will
largely come from drilling and well completions, oil companies claim
continued efficiencies and other mitigations can offset cost increases.


For example, operators pre-purchased goods and services such as
contracting rigs late last year or earlier this year for all of 2018
rather than on an as-needed basis, using locally sourced sand and other
proppants for hydraulic well fracturing, and self-sourcing their goods
and services.

Even so, rising costs “remain a concern,” the Platts Analytics review

The expected 7% to 15% cost increase estimated for this year is on top of
about 10%-15% cost inflation in late 2017, Floyd Wilson, CEO of small-cap
Halcon Resources, said earlier this month in a conference call, echoing
other sources.

“We’ve seen this every time there’s been a major movement in crude prices
for decades,” said Wilson, who is also former CEO of Petrohawk Energy,
which is generally credited with discovering the big Eagle Ford shale
play in South Texas. BHP Billiton bought Petrohawk in 2011.

But capital budget increases appear modest despite higher oil prices,
rising about 10%-15%, according to most accounts. For instance, a Cowen &
Company analysis of 58 E&P companies published Thursday found their 2018
capital spending plans on average were up just 11% over last year.

Further out, consultants Westwood Global Energy Group expects a 15%
year-over-year expenditure rise between 2018-2022 for six major shale
basins that include the Permian, Eagle Ford, the Williston Basin in North
Dakota/Montana, the DJ Basin in Colorado, the Midcontinent plays in
Oklahoma and the Haynesville Shale, a gas play in North Louisiana and
East Texas.

An important variable in spending “will be the relaxation of supply chain
constraints, as service providers add further [fracturing]
capacity…allowing completion activity to accelerate, resulting in a 54%
increase in completion spend this year,” the consultancy said.

— Starr Spencer,

— Edited by Kevin Saville,

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