By - Leslie Haines
Oil and Gas Investor Magazine, January 2003
One surefire way to gauge the interest in, and potential of,
a region is to note how many players want to buy producing as-sets
there, and how much they are willing to pay. By these measures,
South Texas always stands out.
In the last four quarters, buyers paid an aver-age $1.15 per
thousand cubic feet equivalent (Mcfe) for proved gas reserves
in South Texas, according to data from investment-banking firm
Waterous & Co. The region ranked third behind the Upper
Texas-Louisiana Gulf Coast onshore at $1.3 1 and the Gulf of
Mexico, which commands the highest price, at $1 S6. (Re-serves
in eight other U.S. onshore regions gar-nered less money.)
Data from the U.S. Energy Information Ad-ministration show
that Texas Railroad Com-mission District 4-which encompasses
the counties that rise from the Mexican border east of Eagle
Pass to the coast-has almost as much proved gas reserves as
Alaska, and more than Louisiana. In 2001, the latest year for
which data are available, this district alone accounted for
300 billion cubic feet of new-field discover-ies- the most of
any area in Texas, and indeed, more than any single state. And
that doesn’t count upward reserve revisions or many new
reservoirs found in old fields.
Production and the producing-well count have increased at a
1.6% compounded annual rate since 1990. Rigs have increased
at 6% be-cause the number of days to drill have in-creased 4.5%
per year as operators go deeper.
Prospects in the region vary from 20 billion cubic feet (Bcf)
to 100 Bcf and internal rates of return can be 20% or more-but
depletion comes fast too as the new and improved frac techniques
cause the wells to produce at high initial rates, which fall
off. A Texas severance-tax abatement on tight sands has helped.
“In many ways, South Texas is as good a play as the deep
Shelf in the Gulf of Mexico in terms of the average prospect
size. There is not much to differentiate it, except that of
course, you don’t have to build a platform or use boats
and helicopters,” says David Trite, president and chief
executive of Newfield Exploration Co., Houston.
No wonder acquisitions in the region have remained steady during
the past few years. Newfield has been joined by Peoples Energy
Production and Santos Exploration USA as re-cent buyers. Samson
Resources is pursuing deep Vicksburg pay, keeping two or three
rigs operating in South Texas, often partnered with Shell Exploration
& Production. In addition to drilling, in 2002 it purchased
Texas Indepen-dent Exploration Co. for about $45 million, with
reserves in Starr County. It also bought 700 square miles of
3-D in South Texas. It plans to spud two exploration wells-one
to 14,000 feet; the other to 17,000 feet-in early 2003.
“You can pack a lot of reserves in a small area down there-maybe
100 Bcf per prospect [not per well]. Production of 20 million
cubic feet a day is not out of the question,” says Tulsa-based
Samson co-chief executive officer Jack Schanck. Given all this
activity, and the lure of gas re-serves with fast pay out, the
rig count in District 4 has outpaced most other Texas regions
and indeed, the region is second only to Wyoming in the number
of drilling permits granted in the last two years.
That’s not to say it is easy. Many of these wells, whether
drilled to the Frio, Vicksburg, Lobo or Wilcox pays, are highly
pressured and penetrate a complexly faulted subsurface that
resembles shattered glass. They require mas-sive, expensive
fracturing and good technical skills while drilling through
depleted zones or higher pressures. And, they are being drilled
deeper, often below 15,000 feet, as operators seek new gas supply
for North America.
Most players in the region cite land access as one of their
biggest challenges, that is, assem-bling a large-enough block
of contiguous leases to make a meaningful run at glory. Sophisti-cated
ranchers and other landowners, who have been dealing with oil
and gas companies since the1920s, drive a tough bargain. Some
are try-ing to buy back their leases from majors so they can
turn them over to large independents that will explore more
often.
“We had a prospect at Mendiola we’d known about for
three years, but we couldn’t get the acreage at first,”
says Steve Mueller, senior vice president and general manager
for onshore at The Houston Exploration Co. “It took us
six months to negotiate with the landowner and we have a 50-plus-page
lease. And the industry in general has grown more cooperative
and open with its data these days, but in South Texas and offshore,
less so. "Still, what royalty owner wouldn’t like
to be part of a case such as this? In 2000 Houston Exploration
bought properties in the area that were producing 28 million
cubic feet a day, that now produce 68 million because we drilled
20 new wells after the deal closed.”
Despite successes, operators here do still fight the decline
curve. “The balance point be-tween increasing and decreasing
production in District 4 is approximately 1,000 productive wells
per year,” estimates Mueller.
He studied District 4 data from Baker Hughes, IHS Energy and
the state to come up with these findings. “A total of 1,034
wells were drilled in 1998 and production increased slightly.
When the well count dropped to 874 in 1999, production dropped
quickly and then turned round in 2000 with the well count at
1,074. It continued to climb in 2001 with the count at 1,155.”
The biggest producers in South Texas are names you’d expect-Conoco,
Shell, El Paso Production Co., ExxonMobil, EOG Resources, The
Houston Exploration Co. Plenty of smaller and private companies,
and start-ups such as Laredo Energy, Copano Energy, Contango
Oil & Gas Co. and Legend Natural Gas, are staking claims
here as well.
Camden Resources Inc. One relatively new name to the region
is this Dallas-based start-up that was primarily funded In Maverick
County, Saxet Energy Ltd. has a tiger by the tail. It is not
the first time employees of this private Houston company have
enjoyed exploration success in South Texas.
Saxet primarily focuses on Texas Railroad Commission districts
2 and 4, but has added Maverick County in District 1. It drilled
and operated 16 wells in the region last year. Fourteen of those
were drilled in Maverick County, into a series of oil-bearing
reefs, to develop the company’s discovery on the 95 ,OOO-acre
Comanche Ranch lease.
In February 2002, Saxet and its 50% part-ner, The Exploration
Co., hit big with a Cre-taceous Glen Rose oil play in an area
previously thought to be an exploration graveyard. The partners
are now producing about 2,300 barrels per day from seven wells
in the new Comanche-Halsell Field. The wells also produce about
3,800 barrels a day of fresh water, which has caused the partners
to undertake further engineering study to de-termine how to
limit water production. Av-erage depth is 6,500 feet.
Saxet and TXCO’s discovery, the Co-manche Ranch #1- 111,
initially flowed at a rate of more than 2,000 barrels a day
from a 55-foot section of pay, and later flowed about 500 barrels
a day. At press time it was producing about 300 barrels a day.
“We fol-lowed that up with 13 more wells and we’ve
found the porosity zone in almost all of them,” says Saxet
president Robert E. O’Brien.
An additional seven wells are waiting on completion or recompletion.
Cumulative production since February is 560,000 gross barrels
of soil .
The prospects were generated based on 3-D seismic surveys shot
by Saxet and TXCO in 2001. The data indicated more than 30 prospective
Glen Rose areas, the largest covering 850 acres. From the discovery
to the farthest western well is eight miles. “We were drilling
the discovery well when we lost circulation in the top of the
Glen Rose section. We were pumping lost-circulation material
in the well at the same time it was flowing on us, and it produced
5,000 barrels in the first 48 hours, so we knew we had found
something,” O’Brien re-calls.
There are an estimated 30 to 40 prospects on the Comanche Ranch,
with 10 to be drilled by mid-2003. “Each well we’ve
drilled so far was drilled on a different fea-ture,” says
Brian O’Brien, Robert’s father and partner. “One
well does not lessen the risk of the next well until we get
a better un-time derstanding of the play.” Says Robert,
“What makes this so unique is we have not yet found an
analog to it. We believe we have found a new trend. To the north
of us by about 15 miles, Glen Rose produces gas for TXCO. But
this is oil. And whereas TXCO is drilling on a reef, our structure
appears to be a fore-reef facies in a depositional environment.”
There are other deeper zones that look just like it in the
seismic data, which Saxet has not drilled into yet. The O’Briens
theorize that Cretaceous Sligo, James Lime, Pearsall and Jurassic
Smackover equivalents may be productive in the area as well.
“In the Glen Rose there are five intervals and we’ve
only developed one,” says Robert. “Our plans are to
continue to develop the Glen Rose and test the other intervals.
TXCO and others are pursuing coalbed-methane plays near us too,
although we are not presently concentrating on that play.”
Started in 1998 and 50% owned by Quan-Saxet turn Energy Partners,
Saxet has a proud lin-manche eage. Robert started the predecessor
in 1992. In 1997, his father, Brian, and his longtime partner,
Tony Sanchez, dissolved their sto-about ried partnership, Sanchez-O’Brien,
by sell-producing ing their South Texas assets to Coastal Oil
& Gas (now El Paso Production Co.) This in-found eluded
interests in Bob West, one of the largest gas fields in Texas.
“My father [Brian] still wanted to drill wells, so he
and some individuals from the old company joined me to put together
a smaller version of Sanchez-O’Brien,” says Robert
of the new Saxet. “We didn’t buy any assets-we hit
the ground running with our existing prospects.” The strategy
is to generate, drill, develop and exit in a timely manner.
Saxet and its partners have leased in ex-the cess of 300,000
gross acres in the Maverick Basin and have shot in excess of
275 square miles of proprietary 3-D data covering about 50%
of their leasehold in the basin. Might the new Glen Rose oil
play be expanding? “We have a lot of fresh data. Our technical
team is busy now and we’ll hit the ground running in February,”
vows Robert. “We have a tremendous database of both high
tech [seismic data] and low-tech [people’s experience in
the region].
“This Maverick Basin is vastly unex-drilled plored. Shallow
to deep, there is a lot going on.”
wells in which Coastal held an interest, before selling it
outright.Having been involved in one of the best gas fields
in South Texas, Rhoades believes he can find opportunity in
the region again-but this time, deeper. “Most of the shallower
production between 5,000 and10,OOO feet has been found, so the
bigger opportunities will be below that. That’s where your
operational expertise comes in, because the deeper you go, the
more inher-ent the mechanical risks and the expense of set-ting
more pipe.” All but four of Camden’s wells have been
below 11,000 feet and five went below 15,000 feet.
At these depths and in this highly faulted area, constancy
is an attribute that leads to drilling efficiencies. For example,
be-tween Greenbrier and now Camden, he had the same Nabors Drilling
Co. rig under contract for four years. And Rhoades makes a point
of stay-ing on location during critical days to closely monitor
the quality of drilling or cementing op-erations, even though
he also uses Epoch, a software program owned by Nabors. With
this, he can monitor drilling data-including bit depth, hook
load, penetration rate, rotary speed- in real time from his
Dallas office, his home or at the rig itself.
“South Texas is a great place to drill, with great rocks,”
says co-founder and executive vice president Bryant Patton,
“but it’s not for anybody who hasn’t drilled
down here before.” Geology matters, of course. “All
of our prospects contain the four Ss-sand, structure, shows
and what I call scenery. That is, if there are no wells anywhere
nearby and I’m the only guy in town, I’m likely to
back away,” says Rhoades. All but one of the company’s
prospects have been generated based on 3-D data, and all came
from third-party generators.
Patton notes that one of Camden’s biggest problems is
finding enough drill-ready, 3-D-based prospects. Rhoades seconds
that.
“The game has changed,” he says. “You don’t
see people ginning up a lot of prospects because it can cost
upwards of $5OO,OO&that’s a lot of money if you end
up not selling your deal. The costs have gone up because you
have to do 3-D now, which is $20,000 to $40,000 per square mile,
and the land costs are up around $200 to $250 per acre. A standard
lease used to be three pages-now it is 15 and you have to have
an at-torney involved. Your rig costs are probably about a third
of what you are spending.” Next on the agenda, says Patton,
are two wells in Liberty County and a likely offset to the Ruckman
in McMullen County. Longer term, Camden’s strategy is to
build assets through drilling and development, then sell out
in three to five years and start over. “The money is in
finding reserves and then selling them, not producing them,”
Rhoades says. El Paso Production Co.
This company might end up being a buyer someday. It already
incorporates the old Coastal Oil & Gas Co., Zilkha Energy
and Sonat Exploration. El Paso has made South Texas a cornerstone,
with output from the re-gion now totaling about 461 million
cubic feet equivalent a day.
“In 1994 we retooled our business and de-cided to analyze
all the basins and plays in North America,” explains president
Rodney D. Erskine. “We felt most North American plays were
approaching their economic limit, so we set out to become the
experts in unconventional plays such as coalbed methane, the
deepwater Gulf of Mexico-and tight rocks such as you find in
South Texas.”
That commitment is reflected in the com-pany’s activity
level. Through August 2002, El Paso had been operating more
rigs in the U.S. than any other company, according to RigData.com.
Averaging 43, it was well ahead of BP, ExxonMobil, EOG Resources
and Chesa-peake Energy, the next contenders. About a fourth
of El Paso’s rigs were active in District 4. In the past,
El Paso mostly kept mum on its E&P activity due to competitive
leasing pres-sures. But at the RBC Capital Markets invest-ment
conference in Houston in November, Erskine opened up. “More
than half of our net onshore production of 886 million cubic
feet per day comes out of District 4,” he said. The company
claims to have found about 5 trillion cubic feet (Tcf) of reserves-3.45
Tcf proved-in the last few years there.
At Jeffress Field in Hidalgo County, the company found 1.4
Tcf of reserves and has pro-duced 800 Bcfe. “ln 1994, we
thought it had 200 Bcf left, but we determined we’d bypassed
a significant amount,” Erskine says. “Often these
1-Tcf fields were drilled but not under-stood, as they were
so tight. Then we bought a little property next door, Samano,
and we now think it is more than 200 Bcfe-120 Bcfe proved. The
first well initially produced 30 mil-lion a day.”
Production from the Jeffress complex is av-eraging 350 million
cubic feet a day, net, from Vicksburg, he says. The North Monte
Christo Field has 1 Tcf proved and 300 Bcfe probable, while
East Monte Christo has 200- to 500 Bcfe of potential.
Through September 2002 in South Texas, El Paso had racked up
these impressive statistics: 68 wells drilled with an average
total depth of 14,493 feet and an average initial potential
test of 26 million cubic feet per day-and total gross reserves
of 372.7 Bcfe. El Paso said it had 39 prospects last year with
net risked mean potential of 500 Bcf in South Texas.
Newfield Exploration Co. Best known for its offshore growth-by-drilling
story, Newfield has been expanding through onshore acquisitions
lately as well. In its biggest deal yet, it closed on the $640~mil-lion
purchase of EEX Corp. in November. Part of the attraction was
the latter’s extensive South Texas production and drillable
prospects, in-cluding its interests in the storied Bob West
Field near Laredo, one of the largest onshore gas fields found
in the last 20 years-still pro-ducing nearly 100 million cubic
feet per day. The deal brings balance to Newfield’s Gulf
and Midcontinent portfolio and gives it entree to the deepwater
Gulf with EEX’s 60 deepwa-ter blocks. All told, it adds
300 billion cubic feet of proved reserves and an eight-fold
in-crease in acreage.
“We’ve been on a mission to diversify in the last
three years,” says president and chief exec-utive officer
Trite. “As we’ve gotten larger, we recognized we needed
to be exposed to more than a single basin. Now about 40% of
our re-serves are offshore, not 100% as they were originally,
so we feel we are a stronger and more diverse company. This
brings us quality production, legacy fields and a great acreage
position,” says Trite.
“It’s taken us from 1 Tcfe of reserves to 1.3 Tcfe.
We had a footprint in South Texas before [from the purchase
of Headington Oil Co. as-sets in 20001, but now we are a major
player in a bigger playground. We acquired 61 fields and now
have close to 400,000 acres, so we’re in a great place
to look.”
Newfield expects to double the level of capital investment
on EEX’s onshore properties in 2003, to nearly $75 mil-lion.
It aims to repeat what it did with the Head-ington assets, where
it grew production in three fields from about 35 million cubic
feet eyuiva-lent a day to nearly 100 million.
“We’re excited about these assets, their pro-duction
and the exploration ideas that come with them,” says Elliott
Pew, vice president of exploration. “We’re looking
at 40 or 50 wells this year, mostly in Railroad District 4,
with a few in districts 1 and 2. These are identified op-portunities
with a good mix of 25% exploration and the balance, exploitation.”
One star asset in the package is the 35% to 50% working interest
in Dinn Ranch Field in Duval County. Discovered and operated
by EOG Resources, nine successful wells have gross production
of about 80 million cubic feet a day since EOG expanded the
gas-treating fa-cilities at Dinn Ranch last fall.
The play developed out of 3-D shot in the mid- 1990s that led
to significant discoveries in 2000 and 2001. In 2003, the partners
plan at least three development wells.
In Hidalgo County, Newfield will hold 20% to 40% working interest
in wells in Monte Christo Field, a Vicksburg and Frio producer
where one exploratory and five development wells are planned
in 2003.
In Webb County, Newfield picks up 100% interest in Vaquillas
Ranch, where current pro-duction of 10 million a day from 40
wells may be increased. Pew thinks significant proved reserves
can still be developed. In 2003 it plans a field-wide assessment,
remapping and three de-velopment wells. This will be the company’s
first Lobo Trend effort.
Finally, Newfield plans seven development wells in Fashing
Field in Atascosita County, where EEX had 49%. Improvements
such as workovers and lowering the reservoir pressure should
increase production. Newfield also will study the field for
further exploration and ex-ploitation potential.
At press time, Newfield had just completed a proprietary 3-D
survey near Bob West and within the same Wilcox Trend, to try
to extend the trend. Leasing still was under way, so Pew wouldn’t
say toward which compass point the company is looking for new
pay.
“El Paso thinks there’s more life at Bob West,”
says Pew. “But it’s a very large, very complicated
field.”
The Houston Exploration Co. What does it take to be effective
in South Texas? Owing to complex geology, a success-ful exploration
program requires extensive investment in 3-D data and seasoned
personnel to interpret the area’s ambiguous formations,
ac-cording to William (Billy) Hargett, president and CEO.
It also calls for a proactive land group for title work and
negotiation with landowners due to the challenging fractional
ownership struc-ture in the region, and a systematic drilling
pro-gram, because controlling costs is key, he says. THX has
been drilling in South Texas since 1996 and drilled 50 wells
there in 2002 versus 35 the year before. Currently it operates
five rigs in the region and more than 400 wells. Last year it
increased production from Webb, Zapata and Jim Hogg counties
by more than 80%. South Texas yields among the most at-tractive
drilling and production eco-nomics in North America,” Hargett
says. “Our finding and development costs have averaged
around $1.30 per Mcf and lease operat-ing costs are about 25
to 26 cents. Costs to drill and complete wells to the Middle
Wilcox and Lobo Sand typically are from $1 S- to $2 mil-lion.
If gas is $3, we’ll do better than a 20% rate of return.”
THX is hedged to collar the highs and lows so its drilling schedule
remains consistent.
“But it takes a lot of technical expertise. Continuity
of working there over time allows us to increase production
while keeping costs flat.” Hargett vowed to spend less
than company cash flow in 2002 and thus, deferred a few pro-jects
to 2003. It doubled its position in the re-gion to 57,000 net
acres with two acquisitions in 2002. These added proved reserves
of 127 billion cubic feet equivalent (Bcfe) for $111 million.
It has 3-D data on most of it.
“We think acquisitions of production-along with drilling-make
an increase in production more probable. We hope to continue
to expand down there. It is a strategic growth area for us.”
The pay off for all this activity? The company produces about
120 million cubic feet a day net in South Texas, or 40% of total
com-pany production. In fact, THX is the No. 3 pro-ducer in
Zapata and Webb counties-two of the top three gas-producing
counties in Texas. THX-operated properties have more than 1.8
Tcf of gas in place, yet have produced just under 1 Tcf, so
more running room remains. With a drilling inventory of more
than 100 lo-cations on company-operated properties, South Texas
will be a focus for years to come.
The mainstay is still Charco Field in Zapata County, and for
good geological reason. “At Charco we have 80-acre spacing,
but the highly complex faulting often allows us to drill on
as little as 40- and 20-acre spacing and still see no appreciable
communication between wells,” says senior vice president
Mueller. Pro-duction at Charco has tripled since THX ac-quired
it in 1996. A recent acquisition of some additional Conoco interests
around the field means South Texas is now a third of the com-pany
’ s reserve base.
Meanwhile, THX is exploring two new pro-jects in Webb County.
The first is Oilton, a Middle Wilcox farm-in where it earned
12,200 gross acres by drilling two wells. The first dis-covered
two sands and the second reached total depth in December, with
logs indicating similar productive intervals. The second prospect,
in Mendiola, was drilled on a separate structure to test the
Lobo at 5,200 to 6,200 feet.
The area is dominated by huge slumping fault blocks at about
12,000 feet deep, says Mueller. “On our 12,000 acres, there
are 15 dif-ferent fault blocks, give or take, so these are true
wildcats. We’re trying to find out how con-tiguous the
sands are. We’ve always known about the unconformity in
the Lobo, but 3-D has progressed enough to where we can see
it better than we could have two or three years ago,” he
says. “We have reprocessed 1,200 square miles of data four
or five times in the past two years, and some of that has given
us some very good wells.”
Recently, THX contracted with eLynx Tech-nologies of Tulsa
to provide remote real-time monitoring equipment for 242 wells
and 29 gas compressors in Jim Hogg, Webb and Zapata counties.
New wells will be added as they come onstream.
Peoples Energy Production When Chicago utility holding company
Peo-ples Energy decided it wanted to own oil and gas assets,
it hired well-known A&D expert Binney Williamson in 1999
to start looking around. Ideas in South Texas loomed large on
his radar screen.
In September 2000 the company hired vet-eran executive Steven
W. Nance as the new president of its fledgling E&P unit,
and moved it to Houston to pursue an acquire-and-exploit strategy.
At the time there were two or three employees in Houston. Now
there are 30 and production has grown to more than 60 million
cubic feet per day. A big portion is in South Texas, although
the company also has proper-ties in the Arkoma and San Juan
basins and North Dakota.
Many of the first acquisitions focused on South Texas. Peoples
bought Sierra Minerals’ Alvarado Field production and acreage
for $120 million in 2001, its biggest deal so far. Since then
it has drilled 25 wells on these prop-erties, which are in Starr
and Hidalgo counties, and has more than doubled production,
which comes primarily from the Vicksburg.
In June 2002, Peoples acquired an operated position in East
White Point Field north of Corpus Christi for $10.5 million
from Abraxas Petroleum. In November 2002, it acquired properties
from Magnum Hunter Resources for $33 million. That deal included
175 wells in five fields in Webb, Zapata, Colorado and Duval
counties. Peoples will operate four of the five.
“Utilities have been notorious for making some bad investments
in E&P-a lot have stubbed their toe,” concedes Nance.
“We are determined to learn from others’ experience.
Our first deal, in 1998, was a $30~mil-lion equity investment
in EnerVest [a large, private Houston firm that acquires and
operates production for institu-tional investors]. That was
our entree. It let someone else manage the assets. Later we
began investing in nonoperated working inter-ests as we gradually
moved up the risk profile. Today our preference is to operate,
as we have matured into a traditional company with opera-tional
and technical expertise.”
Peoples is changing from being a passive in-stitutional investor
to owning and operating re-serves. In the past two years the
company has spent about $55 million with the drillbit and a
large percentage of that was in South Texas. At press time the
company was reprocessing seismic data from Alvarado Field in
preparation for its 2003 program, which, adds Nance, means a
rig will be busy in the field through March, probably longer.
“The past year was interesting-we looked se-riously at
more than 125 deals, bid on maybe 25, and made only one. I would
like to have spent $100 million but we could not find the right
deals-ones that met our investment criteria and risk profile.
We’ve told the Street our new bud-get is $50 million for
acquisitions and $30 mil-lion for drilling-but if we have an
opportunity to spend more, and it is strategic, we will con-sider
it. But, I am not going to do anything that doesn’t fit
our profile just to show growth.” Nance has been flexible.
In 2000 when his budget was $25 million, he did the Sierra deal
for $120 million, yet in 2001 when his budget was $100 million,
he closed on only a $10.5- million transaction.
“We’re in an ideal situation-we are a start-up company
with a financially stable parent company with capital, that
understands the cy-cles, is disciplined and patient.”
South Texas