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发帖数: 10817 | 1 OIL MARKETS
Fracking’s Secret Problem—Oil Wells Aren’t Producing as Much as Forecast
Data analysis reveals thousands of locations are yielding less than their
owners projected to investors; ‘illusory picture’ of prospects
The wells of some producers in the Permian Basin appear to lag behind
forecasts. ANGUS MORDANT/BLOOMBERG NEWS
85 COMMENTS
By Bradley Olson, Rebecca Elliott and Christopher M. Matthews
January 2, 2019
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Thousands of shale wells drilled in the last five years are pumping less oil
and gas than their owners forecast to investors, raising questions about
the strength and profitability of the fracking boom that turned the U.S.
into an oil superpower.
The Wall Street Journal compared the well-productivity estimates that top
shale-oil companies gave investors to projections from third parties about
how much oil and gas the wells are now on track to pump over their lives,
based on public data of how they have performed to date.
Two-thirds of projections made by the fracking companies between 2014 and
2017 in America’s four hottest drilling regions appear to have been overly
optimistic, according to the analysis of some 16,000 wells operated by 29 of
the biggest producers in oil basins in Texas and North Dakota.
Collectively, the companies that made projections are on track to pump
nearly 10% less oil and gas than they forecast for those areas, according to
the analysis of data from Rystad Energy AS, an energy consulting firm. That
is the equivalent of almost one billion barrels of oil and gas over 30
years, worth more than $30 billion at current prices. Some companies are off
track by more than 50% in certain regions.
The shale boom has lifted U.S. output to an all-time high of 11.5 million
barrels a day, shaking up the geopolitical balance by putting U.S.
production on par with Saudi Arabia and Russia. The Journal’s findings
suggest current production levels may be hard to sustain without greater
spending because operators will have to drill more wells to meet growth
targets. Yet shale drillers, most of whom have yet to consistently make
money, are under pressure to cut spending in the face of a 40% crude-oil
price decline since October.
An oil-production facility near Midland, Texas, owned by Parsley Energy, one
of the biggest producers in the Permian Basin.
An oil-production facility near Midland, Texas, owned by Parsley Energy, one
of the biggest producers in the Permian Basin. PHOTO: NICK OXFORD/REUTERS
Companies whose wells appear to lag behind forecasts, according to the
analysis, include Pioneer Natural Resources Co. and Parsley Energy Inc., two
of the biggest oil and gas producers in the Permian Basin of West Texas and
New Mexico. The Journal’s review didn’t include some leading producers,
such as Exxon Mobil Corp. , because they didn’t make shale-well projections.
Pioneer, Parsley and several other companies disputed the findings, saying
the third-party estimates used by the Journal differ from their forecasts on
key points such as the likely lifespan of shale wells.
Some companies, including major North Dakota producer Whiting Petroleum Corp
. , acknowledged the forecasts can be unreliable and said they were moving
away from providing such estimates.
Another North Dakota driller, Oasis Petroleum Inc., said the projections it
provided in investor presentations were estimates made as it tested drilling
in vast tracts, including areas it has since abandoned. “It’s not a
science,” said Richard Robuck, the company’s treasurer. “It’s more of an
art.”
Few U.S. shale companies disclose exactly how they make their forecasts—the
systems they use and the assumptions they make to estimate well-by-well
production—or whether their projections from years ago hit the mark. The
fact that many have missed is an open secret in the industry.
“I certainly expect many of today’s estimates will turn out to have been
pretty optimistic,” said Francis O’Sullivan, director of research for the
MIT Energy Initiative, which has examined shale forecasting. He said the
complex geology of shale basins and assumptions based on a small number of
wells could make forecasts unreliable. “There is profound variability in
the performance of these wells,” he said.
Schlumberger Ltd. , the oil-field-services giant, reported in a research
paper that secondary shale wells completed near older, initial wells in West
Texas have been as much as 30% less productive than the initial ones. The
problem threatens to upend growth projections for America’s hottest oil
field, the company said in October.
Frackers’ Value Gap
In 2007, before the shale boom, U.S. oil companies were valued more closely
with their proven reserves. Now, the companies' enterprise value, measured
by market capitalization plus debt, is almost three times higher on average.
Enterprise
value
INDUSTRY
AVERAGES*
Value of proven
reserves
Difference
2.8x larger
than reserves
2017: $12.5 billion
1.7x larger
2007: $8.6
2007
15
10
25
5
20
$0 billion
SELECTED COMPANIES
EOG Resources
Pioneer Natural Resources
Continental Resources
Concho Resources
Noble Energy
Whiting Petroleum
45
15
$0 billion
60
30
75
*29 companies (2017); 17 companies (2007)
Sources: S&P Global Market Intelligence data; company disclosures
Oil engineers and reserves specialists say existing data suggests there is a
more accurate way to model well output. Operators, they say, must use more
conservative assumptions about how quickly production will decline and how
many wells can be drilled in a given area. Operators also should avoid
making forecasts without a sufficient sample size of wells, they say.
Flawed forecasting doesn’t mean U.S. oil output is about to drop. Shale
wells reach peak production quickly and rapidly decline, so companies are
constantly drilling new wells. But if thousands of shale wells produce less
over their lifetimes, companies will reap less of a long tail than
anticipated, requiring them to spend more to sustain output and making it
harder for them to reach profitability.
Shale companies have attracted huge amounts of capital from Wall Street over
the past decade. So far, investors have largely lost money. Since 2008, an
index of U.S. oil and gas companies has fallen 43%, while the S&P 500 index
has more than doubled in that time, including dividends. The 29 companies in
the Journal’s analysis have spent $112 billion more in cash than they
generated from operations in the last 10 years, according to data from
FactSet, a financial-information firm.
All oil companies are required to file estimates of total proven oil
reserves with the Securities and Exchange Commission. Those estimates,
governed by strict rules, generally only capture future reserves companies
plan to tap in a five-year period. As the fracking boom intensified, many
exploration and production companies looked for a way to persuade investors
to value their prospects outside of that five-year window.
Shale companies began touting a metric known as estimated ultimate recovery,
or EUR, in investor presentations. The estimates, often represented
graphically by what is known as a type curve, project how much oil and gas
wells are likely to produce over several decades, including the rate of
decline.
Drilling for Capital
As prices crashed, forecasts of greater production per well helped companies
sell new shares.
Crude oil prices
$120
a barrel
100
80
60
40
20
0
’14
’15
’16
’17
’18
2013
Equity Issuance
billion
$40
30
20
10
0
’15
2013
’14
’17
’16
’18*
*Through Nov. 15
Sources: Dow Jones Market Data (prices); Dealogic (issuance)
The practice of promoting EURs became widespread after oil prices crashed in
2014 and producers, many in need of capital infusions from Wall Street,
talked up their prospects. Wall Street’s valuation of many shale companies,
which had been closely tied to the value of their proven oil and gas
reserves, began diverging.
At the end of 2007, the companies in the Journal’s well analysis that
existed at the time had an enterprise value, measured by market
capitalization plus debt, of about 1.65 times the value of their proven
reserves, according to company disclosures and S&P Global Market
Intelligence data. Ten years later, that multiple had risen to more than 2.5
times, even though oil prices were much lower. Last year, the enterprise
value of the 29 companies in the Journal’s analysis was $360 billion higher
than the value of their proven reserves.
EUR estimates from many companies were grounded on two assumptions: that
they could pack wells closer together, squeezing more value from the land
they leased, and that they could replicate their best early wells. The
results to date suggest those assumptions were often wrong.
The Journal’s analysis involves public data that at times gives an
incomplete picture of well performance. North Dakota reports oil and gas
production by well, but Texas does so only by land parcel. Third-party data
providers must extrapolate to make up for that, meaning their data may not
be as precise as well-level data maintained by companies.
The Journal relied primarily on figures from Rystad Energy, but consulted
with several other third-party providers, including Oseberg Inc. and BLR
Digital LLC, whose data pointed to similar conclusions. Those providers
forecast well output over several decades based on early, publicly reported
production data, taking into account typical decline rates.
Some companies, including major North Dakota producer Whiting Petroleum,
acknowledge individual well forecasts can be unreliable. A Whiting facility
near Williston, N.D.
Some companies, including major North Dakota producer Whiting Petroleum,
acknowledge individual well forecasts can be unreliable. A Whiting facility
near Williston, N.D. PHOTO: BAYNE STANLEY/ZUMA PRESS
When oil prices plummeted around 75% between 2014 and 2016, to below $30 a
barrel, many shale companies used EUR estimates to try to persuade investors
that the sector remained a strong place to put their money.
The production forecasts made by many companies were “dangerous” because
they were based on a small population of wells, and the performance of
individual wells varies significantly, said Norman MacDonald, a natural-
resource specialist at asset manager Invesco Ltd.
“Companies were able to high-grade the numbers, show those to Wall Street,
and the stock price went up accordingly,” said Mr. MacDonald, a portfolio
manager who has urged shale companies to prioritize profits over production
growth. “Geology doesn’t line up with Excel spreadsheets too well,
unfortunately.”
In September 2015, Pioneer Natural Resources, based in Irving, Texas, told
investors that it expected wells in the Eagle Ford shale of South Texas to
produce 1.3 million barrels of oil and gas apiece. Those wells now appear to
be on a pace to produce about 482,000 barrels, 63% less than forecast,
according to the Journal’s analysis.
An average of Pioneer’s 2015 forecasts for wells it had recently fracked in
the Midland portion of the Permian Basin suggested they would produce about
960,000 barrels of oil and gas each. Those wells are now on track to
produce about 720,000 barrels, according to the Journal’s review, 25% below
Pioneer’s projections.
Pioneer disputed the conclusions, noting that it assumes its wells will
produce for at least 50 years, while Rystad Energy uses 30 years in its
forecasts. Pioneer also assumes its well productivity will fall off at a
slower rate than the 7% final decline rate Rystad assumes.
“We find it is simply impossible to compare the numbers due to the
methodological differences,” a Pioneer spokesman said.
A Pioneer Natural Resources facility in the town of Big Lake in West Texas.
A Pioneer Natural Resources facility in the town of Big Lake in West Texas.
PHOTO: JOYCE MARSHALL/STAR-TELEGRAM/ASSOCIATED PRESS
Adjusting for those factors doesn’t fully make up for the disparity in
production forecasts. If Pioneer’s wells produce for 50 years and decline
at 5% annually, its current production trajectory would still be nearly 12%
below the company’s forecast of 849,000 barrels of oil and gas in the
Permian, according to the Journal’s analysis. In the Eagle Ford, estimated
production would increase only slightly to 498,000 barrels, or 62% less than
the company projected.
A spokesman for Pioneer said problems in the Eagle Ford in 2015 were “
widely known,” and the data shows the company’s well performance has
improved.
While it is difficult to know how long shale wells will remain productive,
assuming tens of thousands of them will pump for 50 years without costly
interventions to keep them flowing is extremely optimistic, according to
specialists on reserves.
The oldest case study to date is in the Barnett shale in and around Fort
Worth, Texas, where modern fracking began about 20 years ago. Researchers at
the University of Texas and Rice University predicted that many wells in
the region, which primarily contains natural gas, won’t even produce for 25
years. About 73% or more of the total output of wells will come in the
first decade, with little value coming after 20 years, the researchers said.
The decline rates of as low as 5% that some shale companies have adopted for
their wells are optimistic, some academics and industry leaders say. Recent
studies by Rystad and analytics firm Wood Mackenzie Ltd. found that a range
of 12% to 16% was the most common decline rate after about five years.
In 2014, Parsley Energy, an Austin, Texas-based producer, told investors its
average well in the Midland section of the Permian Basin would produce 690,
000 barrels, according to a review of Parsley’s quarterly earnings
presentations. By 2015, its estimates averaged 1,050,000 barrels.
Parsley is on track to miss its Midland well forecasts for every year from
2014 to 2017 by an average of 25%, according to the Journal’s analysis.
“Responsible evaluation of the data shows that Parsley’s historical well
production has been consistent with expectations set forth in our public
materials,” said a Parsley spokeswoman.
When calculating its estimates, Parsley includes other valuable hydrocarbons
that come out of wells, such as ethane. In its analysis, Rystad doesn’t
include those hydrocarbons, known as natural gas liquids, because they aren
’t accurately captured in available public data.
Parsley declined to comment on how much of a boost its estimates get from
such liquids. In recent years, the average increase in barrels from
including the byproducts amounts to 10% to 18% in the Midland basin,
according to third-party estimates.
Mark Papa, chief executive of Centennial Resource Development, said his
company avoids well forecasts because they create an ‘illusory picture’ of
a company’s prospects.
Mark Papa, chief executive of Centennial Resource Development, said his
company avoids well forecasts because they create an ‘illusory picture’ of
a company’s prospects. PHOTO: F. CARTER SMITH/BLOOMBERG NEWS
Mark Papa, a fracking pioneer and chief executive of Centennial Resource
Development Inc. in Sugar Land, Texas, said his company avoids forecasts
because they create an “illusory picture” of a company’s prospects. “A
lot of type curves present a well’s potential under perfect conditions,”
he said. “But in reality, the majority of the wells don’t turn out that
way.”
Some companies said they were aware of flaws with the forecasting method and
how it has been used, but that they provided the numbers to meet demands
from analysts and short-term investors such as hedge funds. Some said that
if they didn’t, their stock would underperform peers that made optimistic
claims.
“You have to make projections,” said David Lancaster, chief financial
officer of Matador Resources Co., a top Permian driller. He said companies
should revise forecasts that appear to be off target, disclose production
ranges rather than specific estimates and avoid screening out poorly
performing wells.
Matador’s average well in the Permian’s Delaware Basin is on track to
outperform forecasts in all three years the company provided them, according
to the Journal’s analysis.
Whiting Petroleum is de-emphasizing its per-well production estimates at the
direction of its chief executive, Bradley Holly.
Whiting Petroleum is de-emphasizing its per-well production estimates at the
direction of its chief executive, Bradley Holly. PHOTO: ELLIOTT D. WOODS
FOR THE WALL STREET JOURNAL
Denver-based Whiting Petroleum is de-emphasizing its production estimates at
the direction of its chief executive, Bradley Holly. Mr. Holly, who became
CEO in November 2017, said the company is now more focused on generating
cash, lowering debt and maximizing a well’s returns early in its life.
“Your return will really be made in the first two to three years,” he said.
One reason thousands of early shale wells aren’t meeting expectations is
that many companies extrapolated how much they would produce from small
clusters of prolific initial wells, according to reserves specialists. Some
also excluded their worst-performing wells from the calculations, which is
akin to eliminating strikeouts when projecting a baseball player’s batting
average.
“There are a number of practices that are almost inevitably going to lead
to overestimates,” said Texas A&M University professor John Lee, an expert
on calculating oil and gas reserves.
Many reserves specialists have advised companies to provide a potential
range of outcomes based on their internal analyses, a common practice in
statistics that better accounts for uncertainty.
Academic research has suggested that data from at least 60 wells, producing
for six months or more, would be needed for accurate forecasts. Yet some
companies and analysts have made predictions based on fewer than 10 wells.
At a July presentation Mr. Lee gave in Houston about techniques that could
produce more accurate shale forecasts, one participant stood up and
challenged the engineers in attendance.
“Why aren’t we doing this?” the man asked several times, according to Mr.
Lee and two other people who attended the meeting.
“Because we own stock,” replied another engineer, sparking laughter.
Write to Bradley Olson at [email protected], Rebecca Elliott at rebecca.
[email protected] and Christopher M. Matthews at [email protected]
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