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ANALYSIS:
US COALBED METHANE
High
commodity prices don't deter interest in unconventional gas plays;
The eclipse of a 24-year-old record in drilling permit activity is
one indication that interest in US Rocky Mountain gas resources is
at a high point. Another is the continued activity in buying and selling
assets, even in the face of high commodity prices. David Wagman reviews
the major drivers behind recent acquisition activity in coalbed methane.
December 1, 2004
Copyright 2004 McGraw-Hill, Inc.
Laramie Energy was granted drilling permit No. 2,379 by the Colorado
Oil and Gas Conservation Commission in early November, marking the
end of a 24-year-old record. The permit, for a natural gas well in
western Colorado's Piceance Basin, meant that the total number issued
beat an earlier record for permit activity set back in 1980, during
the Rocky Mountain's last oil and gas boom.
New records are also likely this year in the amount and value of produced
oil and gas. The value of Colorado energy production this year is
expected to hit $6.6 billion, above last year's $5 billion.
Starring Coalbed Methane
And ongoing high commodity prices are also lending star power to coalbed
methane, an unconventional play, which only a few years ago was being
coaxed to life with the help of a US federal government tax credit.
With natural gas prices now in the $5-$6/million cu ft range, market
forces are able to sustain coalbed methane production without tax
breaks. Interest exists among many companies to acquire either assets
or entire companies with coalbed methane prospects.
"With today's economics, resources that were seemingly uneconomic
are getting a new look," said Arthur Smith, chairman of consultants
John S Herold, in Houston. That means more drilling permits and heightened
interest in buying and selling coalbed methane assets.
Coalbed methane is a methane-rich, sulfur-free natural gas contained
in underground coal beds. The resource has been difficult to recover
in the past due to issues related to geography, geology and technology.
The easy availability of conventional natural gas plays also left
coalbed methane largely uneconomic. And the relative lack of pipeline
capacity - especially in the Rocky Mountain West - made it hard to
transport gas to major market centers.
These issues have, largely, been addressed in recent years. Production
downturns in conventional gas plays, coupled with unprecedented high
commodity prices, have focused the spotlight on coalbed methane and
its primary producing regions, which stretch across parts of the US
states of Wyoming, Montana, Utah, Colorado, New Mexico, Kansas, Oklahoma
and several Appalachian states in the East.
Creating Value
Brokers Raymond James observe that acquisitions are not being made
for an existing production stream, but for the ability to expand production
through capital spending. In a June research note, Raymond James said
that companies in the E"P sector consistently reinvest at least
70% of their cashflow.
After XTO Energy closed on its $1.1 billion ChevronTexaco property
deal last May, it announced a 20% increase in capital spending, from
$500 million to $600 million. "That's how acquisitions create value,"
a Raymond James analyst commented.
Among other recent deals:
- In
December 2003 Quest Resources paid $126 million to Devon Energy
for coalbed methane assets in the Cherokee Basin in Kansas;
- In
May 2004 XTO Energy paid between $336-341 million to ExxonMobil
for properties in the Powder River Basin and elsewhere;
- That same month Pioneer Natural Resources
acquired Evergreen Resources for $2.1 billion ($7.34 per barrel
of oil equivalent-boe). In September Heartland Oil and Gas paid
$22 million for Evergreen's Forest City Basin coalbed methane
assets;
- In a third major May deal, Encana acquired
Tom Brown Inc for $2.7 billion ($12.38/boe), including properties
in the Rocky Mountains;
- In October, Western Gas Resources paid
$82.2 million to four sellers in New Mexico's San Juan basin for
24,000 net acres producing 11 million cu ft/d net of coalbed methane.
Proved reserves were put at 60 billion cu ft with additional upside
of 50 billion cu ft;
- And, in November, St Mary Land "
Exploration closed on a $23.1 million deal with Goldmark Engineering
to buy an estimated 32 billion cu ft(e) of proved oil and gas
reserves in Wyoming's Big Horn Basin.
A closer look at
one deal may be instructive. Analysis by Raymond James suggested that
Evergreen was taken out for around $1.43 per proved million cu ft(e).
That was at a discount compared against a comparable group of small-cap
companies, which Raymond James follows. Proved reserves among those
companies had an average value of $1.94/million cu ft(e).
Evergreen's purchase price was also at a discount compared with the
value of proved reserves across the entire E&P sector, which was $1.82.
Raymond James said the discount was the result of coalbed methane's
long reserve life. In the case of Evergreen, its reserve life at the
end of 2003 was around 32 years.
Pennaco Energy fails to sell
One exception that bucked the trend was Marathon Oil's Pennaco Energy,
which failed to sell. Marathon is one of the largest coalbed natural
gas acreage holders in the Powder River Basin with more than 650,000
net acres in northeast Wyoming and southeast Montana. Production from
these operations averaged approximately 72 net million cu ft/d during
the first quarter of 2004.
At year-end 2003 Marathon's total resource base in the Powder River
Basin was around 2 trillion cu ft of natural gas, of which 388 billion
cu ft were booked as proved reserves. The company took coalbed methane
producer Pennaco off the market in October, saying the offers it received
didn't match its expectations. Production didn't appear to be growing
as it was expected to do, and looked to be flat or even declining,
said John S Herold's Arthur Smith.
With commodity prices up, many companies see this as a good time to
take "some or all of the chips off the table", said Dane Isenhower,
vice president and general manager for Houston-based Petroleum Place
Energy Advisors. Buy and sell activity is up. So are multiples. In
2003, dollar-per-barrel-of-oil-equivalent multiples were around $7
a barrel, Isenhower said. By late summer and early fall they were
above $8.
Specialist M&A advisors Randall & Dewey have noted a trend in implied
reserve values for all recent transactions, which included conventional
as well as non-conventional gas properties. The firm said implied
reserve values reached a record high $9.12/bbl of oil equivalent (boe)
in the second quarter, up from $6.01/boe in the first quarter and
$6.75/boe in 2003.
G Warfield "Skip" Hobbes, managing partner with Ammonite Resources,
based in New Canaan, Connecticut, said one coal producer was taking
advantage of the high commodity prices by partnering with a hydrocarbon
producer to drill in a coal seam it doesn't plan to mine for another
20 years. The producing company has a 70% interest in the gas and
the coal company stands to save the future expense of degassing the
coal.
Buyers appear willing to pay for upside potential. In the past, sellers
could seldom expect to get twice the value of an asset's proven developed
reserves (PDP). That isn't doctrine today, Isenhower said, as sellers
are increasingly able to realize more than twice PDP.
Energy still cyclical
It's not all upside, however. Buyers, sellers and equity lenders alike
recognize energy's cyclical nature. A warm winter, a drop in demand
or a sizeable jump in rig count could help drive prices down from
their current high levels. And even though coalbed methane properties
tend to be long-lived producers, they can also take longer to bring
into production, in part due to dewatering issues. Coalbed methane
is also proving to be anything but homogeneous, a factor that can
also lead a company into danger. "Coal can be highly variable stratographically,"
said Hobbes.
Geological studies are critical for buyers who need to determine the
thickness and quality of the coal within an asset. "If a company acquires
20,000 acres on the strength of three wells and says they will put
in 200 wells, they may run into trouble," Hobbes said.
Sylvia Barnes of investment advisors Petrie Parkman agreed, saying,
"not all coalbed methane is created equal." During the 1990s she worked
for an institution that bought coalbed methane assets in the San Juan
basin. It proved to be "almost magic gas" with production that consistently
exceeded independent third-party engineering forecasts. "It gets back
to permeability and porosity," she said. "There are aspects of coalbed
methane that are still not fully understood."
Having a good geological report is
one part of buying an asset. But so are at least four other factors:
- can
water be disposed of on the surface (a cheaper option) rather
than through reinsertion (a more expensive option)?
- is
the permitting process favorable?
- is adequate pipeline capacity available
to take gas to market? And
- is enough electricity available
to operate the necessary equipment?
Skip Hobbes said
that so much electricity-consuming equipment is running in the Powder
River Basin that some firms are considering building power generators
for their own power needs and for resale to neighbors.
High commodity prices are also causing buyers to think twice about
acquiring proven reserves. "We don't recommend buying proven reserves
at today's prices," said Hobbes. A better strategy, he suggested,
might be to acquire unproven reserves and benefit from the upside
when the asset moves to the proven reserves column.
Concerns also exist that commodity prices may be at or near the top.
Last spring, Randall & Dewey wondered if 2002 and 2003 were the first
stages of a multi-year robust price scenario with mid-cycle prices
well beyond historical averages. Or, the firm asked, is the market
closer every month to a major cycle peak? It said the answer might
be "yes" to both questions.
But Raymond James doesn't include itself among analysts predicting
a correction in 2005. Instead, the company believes that investors
are comfortable with the commodity's ability to sustain current high
prices. The firm is bullish in $40 a barrel oil and $6.65/million
cu ft natural gas.
And Peter Dea, chief executive of Western Gas Resources, sees natural
gas prices for the next few months in the $8 range, three to four
times acquisition cost.
Hedging their bets
Since no one is really certain where prices are going, hedging strategies
are being used to protect cashflow earmarked for debt repayment. Many
companies use hedging strategies to lock in a known rate of return
for part of any recently acquired production, said Dea.
Pioneer Natural Resources hedged roughly three-quarters of Evergreen's
production through 2005, said Sylvia Barnes. When Kerr-McGee presented
its offer to acquire Westport Resources, Barnes said the purchase
did not appear to be accretive using first call estimates. The deal
looked more robust, however, once forward market price forecasts were
included. She said Kerr-McGee's plan was to hedge as much as 90% of
Westport's proved production through 2006.
And when Quest bought Devon's coalbed methane assets, equity lenders
required that 80-85% of production be hedged to guarantee cashflow
for interest payments. At the time, Devon's assets were producing
an average of around 19,600 gross million cu ft per day.
"It would have been our preference not to hedge," said James Vin Zant,
head of industrial relations for Quest. Over a three-year period,
the company's hedging has an average value of $4.70/million cu ft,
which Vin Zant said was "substantially below" current natural gas
prices.
First mover advantage
Even with a hedging strategy in place, buyers can make money on the
spread between the commodity price and the natural gas forward strip
price, Barnes said. That's because the wellhead price of natural gas
has risen from roughly $1 to $2/million cu ft between 1998 and 2004.
At the same time, the NYMEX blended natural gas forward strip - with
70% gas and 30% crude - has risen from roughly $2.50 to $6.25.
"That's what is driving the acquisition market," Barnes said. For
those who have sold into those market conditions, the result has been
an "extraordinary return". She does not expect the margin to remain
wide over the long term, however. Either acquisition prices will rise,
or the forward strip will flatten, narrowing what up until now has
been a significant first-mover advantage.
Not every company is willing to get into the buying and selling game.
An analysis of deals done in 2003 suggested to Randall & Dewey analysts
last spring that more than 80% of the transactions involved independents
as buyers. And independents made up 66% of all sellers.
The analysis also showed that a "vast majority" of buyers were publicly
held independent companies. A similarly large majority of sellers
were privately held independents. The firm said that many private
companies were better able to cash in when prices were high. Few public
companies have the same flexibility, given Wall Street expectations
for quarter-to-quarter growth.
Ammonite Resources' Skip Hobbes said that a good supply of assets
may be available from the universe of relatively small, undercapitalized
companies "that got in and ran out of money."
He said his firm is aware of a "number of situations" in which well-capitalized
companies are looking to buy small E&P firms that have potential reserves
but lack access to capital. "If you have proven reserves it's easy
to get capital," he said.
One small company that has been actively buying acreage in the Powder
River Basin is Denver-based Galaxy Energy Corp. Founded last year
by Mark A Bruner, who sold Pennaco Exploration to Marathon Oil in
2002 for $500 million, Galaxy has either drilled or acquired 140 wells,
spending $20 million in the process.
The company recently arranged another $20 million in financing to
drill 100 additional wells during 2005. The company plans to have
around 285 wells operating in the Powder River Basin by the end of
next year. "We prefer to drill our way in," said Cecil Gritz, chief
operating officer. "We're getting into areas where the big guys have
left to go to do something else."
In July this year Galaxy agreed to acquire 4,400 net acres of prospective
coalbed methane properties in Campbell and Converse Counties, Wyoming.
Under terms of the deal, Galaxy must drill 12 new wells on the acreage
to earn an initial 50% working interest in those wells along with
a 50% working interest in nine existing wells, seven of which have
already been completed.
Galaxy made an initial payment of $100,000 and estimated it may need
to spend another $1.2 million for drilling and associated infrastructure
expenses.
Skip Hobbes doesn't see commodity prices dropping to the point where
coalbed methane becomes uneconomic to produce. "We made money at $3/million
cu ft," he said. With demand keeping prices high, the key - as always
- is owning the resource.
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