In December 2007, Range Resources Corp. announced the newest US shale gas play, reporting three new horizontal Marcellus tests that made 3.7, 4.3, and 4.7 MMcfe in their first 24 hours. Just more than three years later, more than 2,500 horizontal wells have now been drilled through the Appalachian Formation, making a combined 2.5 Bcf per day, of which some 10% is being surfaced by Range alone.

And exploration of its and fellow leaseholders’ acreage is far from exhausted. In the coming 30 months, some 125-plus rigs will drill 6,000-plus wells and do 50,000-plus frac stages in the play, estimated Robert MacKenzie, managing director, energy and natural resources, FBR Capital Markets.

Why drill this gas at below US $5? The reasons are plenty. The Marcellus offers both dry gas and yet-higher-premium, Btu-rich gas liquids in a fuel-thirsty Northeast market. Some production is 1,400 Btu, or 1.4 times, the energy content of a thousand cubic feet of dry methane, so the actual price producers are fetching is $6-plus per Mcf when factoring in the liquids.

Other reasons are market anomalies. A great deal of drilling is being paid for by US producers’ joint-venture partners in the play, from Statoil, Mitsui & Co. Ltd., and Sumitomo Corp. to Reliance Industries Ltd.

Demand for rigs and pressure-pumping crews is expected to grow in the Marcellus play. (Source: FBR Capital Markets)

Also, some early leaseholders are rushing to hold their acreage before the initial term — usually five years — begins to expire in 2012 and 2013. Lease renewal is possible, but at a new price: Early entrants put together land at less than $100 an acre; today, entry costs $7,000-plus an acre in outright purchase, and entry via joint venture is averaging $14,000-plus.

The No. 1 lease owner in the western Pennsylvanian heart of the play, Range Resources Corp. has pared its lateral lengths, for example, to stretch its capex budget and beat the clock on the expiration of a large portion of the 1.1 million acre portfolio it’s amassed, almost all of this in 2007 and 2008 before its late-2008 initial well news set off the land rush.

A Pennsylvanian-age black shale up to 900 ft thick in some areas at depths of between 2,000 and 7,200 ft, the extent of how much gas the Marcellus will give up is still yet to be determined. For example, Range reported a 10 MMcfd well in 2009 — the highest IP yet in the Marcellus at the time. More recently, Cabot Oil & Gas Corp. drilled two 30 MMcf IP wells.

Not even on the super major gas field map four years ago, by 2009 the Marcellus was catapulted to the “second-largest gas field in the world” spot by industry and academia as well results began to prove the production potential. Even Russia has taken notice: It is no longer the world’s No. 1 gas producer, as Marcellus and other US shale gas output pushed the US to that title in 2009 in an annual BP Plc global oil and gas review.

The BP research team’s 2010 report, which is due this summer, is expected to find the US continuing to hold that top position as gas exploitation has yet to slow down and as the Marcellus play, while nascent, is better understood with each well, lateral, and frac job. Producers report decline rates are flattening and EURs are growing.

The Appalachian output is turning gas market dynamics on its head in the US and even globally as the new indigenous supply within the world’s top gas market will mean LNG imports to US shores remain noncompetitive. And North American petrochemical manufacturers are enamored by the Marcellus’ NGLs, particularly the ethane and propane that are low-cost feedstocks compared with crude oil-based naphtha.

Producers’ greatest emphasis in their Marcellus programs now is on monetization of the bounty.

Slower declines, growing EUR

At press time, Cabot reported new whopper Marcellus wells: IPs from the pair came in at some 30 MMcf each, with 21 and 26 frac stages and lateral lengths of between 5,000 and 6,000 ft. The company’s average well previously IP’d at 16 million MMcf, and the newest wells suggest an EUR of at least 15 Bcf per well.

The wells cost some $7.5 to $8 million. “This sort of type curve should generate acceptable economics with gas as low as $2,” said Biju Perincheril, equity-research analyst for Jefferies & Co. Inc.

In north-central Pennsylvania, longtime Rockies gas producer Ultra Petroleum Corp. expects to have twice as many wells online this year as last, more than doubling production. First-quarter 2011 net output alone of 93 MMcfd was as much as half of full-year 2010 production. It might get to 150 MMcfd this summer.

“Our decline curves are getting flatter, and our EURs are increasing,” said Mike Watford, Ultra chairman, president, and CEO. For example, the EUR on its Kenton 902-1H well was 3.8 Bcf after 60 days of production. After 150 days online, it is now expected to make 4.8 Bcf, or 26% more.

Ultra holds 260,000 net acres, with some of its gross position operated by Shell Oil Co. via the major’s purchase of private Appalachia-focused independent East Resources Inc. last year. Some is operated by Anadarko Petroleum Corp.

Lately, Ultra’s Marcellus wells — of which there are 105 gross — have an average lateral of 5,173 ft and 14 frac stages. IPs are averaging 6.5 MMcf. In western Tioga County, Pa., the 6,700-ft-lateral Pierson 810 5H well with 27 frac stages went into sales at 10 MMcfd. An offset, it has an EUR of more than 8 Bcf.

“It's one of our best wells in the field,” said Doug Selvius, Ultra director, operations. “It appears EURs for these new long-lateral wells could be nearly twice our 3.75 Bcf-type curve.” The B factor it has been using in the play is 1.7; indications are that 1.5 or less may be more accurate, added Brad Johnson, vice president, reservoir engineering and development.

In Butler County, Appalachia-based Rex Energy Corp. is using more sand and tighter clusters in its completions. Its IPs are averaging 3.6 MMcf on three wells on which it used a new, enhanced frac design, and indications are that the EUR is 4.4 Bcf there. In Westmoreland County, two new Rex wells operated by Williams Cos. Inc. averaged 3.4 MMcf/d in their first 155 days online, exceeding the area’s type curve of 3 MMcf/d and an EUR of 3.0 Bcf.

In northeastern Pennsylvania, where Southwestern Energy Co. has some 173,000 net acres that are prospective for Marcellus, it made 2.8 Bcf, net, in the first quarter — 4.5 times its fourth-quarter 2010 net. It is also posting some remarkable 90 day-plus production figures: Three wells in the Greenzweig area in Bradford County that came online in October are making an average 6.3 MMcf/d each, three online since November are making 4.3 MMcf/d each, and three online since February produce 5.8 MMcf/d each.

“We're getting all of the infrastructure in place … We're really excited that the wells are coming in much better than we expected,” said Steve Mueller, Southwestern president and CEO.

Southwestern pioneered the Fayetteville Shale gas play in Arkansas, so it is well-versed in shale well engineering and economics. There, a 10% return to investors is being made at just under $4 gas; in the Marcellus, Mueller said, “even three months ago, we were talking about it being in the $3.80s. Now, we're talking in the low $3s.”

For Pittsburgh-based Consol Energy Inc., the Marcellus made 4.7 Bcf in the first quarter, four times the company’s year-earlier sales. It tripled its leasehold in that time frame to total 750,000 acres by buying 500,000 acres from Dominion for $3.5 billion in cash. “There were a lot of questions about that,” said Brett Harvey, Consol chairman and CEO, “but it’s showing very good results … And now we've shown very good results in the questionable (Marcellus) areas that we purchased in central Pennsylvania.”

Bill Lyons, Consol chief financial officer, added that all of its leasehold is held by fee or production so “we were able to drill for economics as opposed to holding leases.”

The rush to HBP

While some operators are reporting 9,000-ft laterals and more than 20 frac stages with IPs of 15 million-plus, Range Resources is focused on holding its acreage right now, using average lateral lengths and frac stages.

Range will spend some 86% of its $1.4 billion 2011 capex budget in the play, with some of the funds coming from the $900 million sale of its gas-prolific Barnett Shale properties. The love the Marcellus is showing Range is so rewarding that it expects to grow companywide production 10% this year, even without the Barnett contribution that made some 25% of its total output last year.

Marcellus wet gas further drives the economics of the play, and its dry gas receives premium pricing, making it profitable to produce in a lower gas-price regime. (Note: Average for all producers; some producers have better or poorer individual-well IRR. Source: FBR Capital Markets)

By the end of this year, it expects to have 400 MMcf/d into sales, up from 200 MMcf/d in December. At year-end 2012, it expects to be producing 600 MMcf/d. Even more remarkable: Most of this growth will be from wells having modest 2,500-ft laterals and eight-stage fracs.

Jeff Ventura, Range president and COO, said, “Our plan for 2011 is to drill moderate lateral lengths and fewer wells per pad and retain our acreage in this prolific play, not only for the Marcellus potential but also for the Upper Devonian and Utica shales.”

It has 285,000 net acres HBP now and 790,000 more left to hold. The average 2,500-ft-lateral, eight-stage frac well in its southwestern Pennsylvania acreage costs some $4.1 million and proves an EUR of 5 Bcfe. At $5 gas, that’s a 99% rate of return. Even at “$4 gas forever,” Ventura said, it’s 74%.

“It’s not (more) optimal (than longer laterals and more stages), but it’s pretty darn good … We can drill more wells and hold more acreage and still generate really strong rates of return.”

Dave Porges, chairman, president, and CEO of EQT Corp., which holds 3.4 million acres in Appalachia that it has targeted for other formations, said that, when drilling for both well economics and to hold acreage, “it is probably true that shorter laterals make more sense because what you want to do in that circumstance is touch as many of those leases as possible.”

Early entrants to the play that secured five-year lease terms will be approaching expirations in 2012 and 2013. But, if able to drill solely for top well economics, “we are absolutely convinced that longer laterals are better, at least up to 9,000 ft, which is as far as we’ve drilled to date,” Porges said.

EQT plans a few longer laterals this year, but its average new-well lateral will be at least some 9,000 ft. “We are absolutely convinced, based on what we’ve done, that longer is better from an economic standpoint,” he said.

EOG Resources Inc. is also working to HBP. “(On) the dry-gas side of our ledger, we're focusing essentially … where we have to drill to hold acreage: The Marcellus, Haynesville and, to a lesser extent, the Horn River (Basin),” said Mark Papa, EOG chairman and CEO.

The company planned to sell its Marcellus position last year to fund its many other high-potential plays — particularly oily ones — but the deal came undone. Papa said he isn’t interested in putting EOG’s Marcellus leasehold into a joint venture — a tack several other producers are using to pay half or more of drilling costs and to free cash for developing more Marcellus and other assets.

Papa said, “The question really boils down to ‘Do we want to devote some of our staffing to basically educating someone else on a shale play and we do 100% of the technical work for perhaps a 50% net interest in the production?’ We would just prefer to do 100% of the technical work for 100% of the production.”

Take-away, export

Where does all the gas go? Alan Armstrong, president and CEO, Williams Cos., which is both a producer and pipeline operator in Appalachia, said, “The Marcellus is really infrastructure-constrained on many fronts right now.”

About two thirds — that is, 1.3 Bcf a day, up from 500 MMcf a year ago — of all Marcellus production from Pennsylvania this spring was going into the Tennessee Gas Pipeline (TGP), which El Paso Corp. operates. The company has $1 billion of expansion projects under way in the northeastern US, including the 30-in.-diameter 300 Line, to keep up with the growing output.

Some producers are more takeaway-advantaged than others. Range is prepared to handle the 400 MMcf/d it expects to be making from Marcellus at year-end — and more. In southwestern Pennsylvania, its Houston 3 processing plant will bring capacity to 335 MMcf/d, and its Majorsville 2 plant will add more, totaling a combined 390 MMcf/d. Also, gathering capacity from the wellhead will be 575 MMcf/d by year-end, said Ventura.

All of this burgeoning Marcellus production is expected to affect gas markets across North America on a level not seen since, possibly, the completion of the Rockies Express (Rex) pipeline into Appalachia from the west or the 1 Bcf/d Independence Hub line, Independence Trail, from the deepwater Gulf of Mexico.

Ultra Petroleum’s Marshal Smith, CFO, said the additional Marcellus supply will back out gas that normally goes into the US Northeast from the Gulf Coast and elsewhere in the Lower 48 and from Canada. “So then you get backed up in both regions … We’re seeing the results of that, and we'll continue to see the results in terms of a further narrowing of basis differential and a flattening of basis differential across the country.”

James Crandell, commodities research analyst for Barclays Capital, noted that net daily imports into the Northeast declined by 0.6 Bcf in 2009 from 2008 and another 0.5 Bcf in 2010. “Indeed, pipeline operators have been reacting by requesting, and receiving, permission to reverse the direction of flow on pipelines that traditionally hauled Canadian gas to the Northeast,” Crandell said.

Yet, said Greg Ebel, president and CEO of midstream operator Spectra Energy Corp., “If you go out 20 years, you're still going to find about 40% of the gas produced in the Lower 48 coming from the Gulf Coast region.”

Far out on the horizon, the back-up in Appalachia may be relieved by the export of US gas, which would also push up US gas prices. In mid-May, LNG operator Chenier Energy Inc. received Department of Energy (DOE) approval to export gas from South Louisiana to any country with which the US does not prohibit trade. It is now working for Federal Energy Regulatory Commission permits to construct the 2 Bcf/d liquefaction facility at its existing Cameron Parish, La., LNG import terminal. The target construction completion date is 2015.

Upon news of the DOE permission, the Nymex price of natural gas for June delivery jumped 26 cents to $4.34; for December 2015 delivery, 18 cents to $6.45; and, for April 2016 delivery, 17 cents to $6.16.

Also on the Gulf Coast, Freeport LNG Development LP has made a similar application to the DOE and would export gas from its Freeport, Texas, LNG import facility.

Market watchers expect that most of the gas exported from the Gulf Coast would come from neighboring areas — including the Eagle Ford, Barnett, and Haynesville Shale gas plays. This would take pressure off Gulf Coast gas flow into Appalachia and improve the price for local Marcellus gas.

Yet possibly on the horizon as well is the export of Appalachian gas itself —f rom Dominion Resources Inc.’s Cove Point LNG import terminal in Maryland, where Statoil is among buyers of imports and is also a Marcellus gas producer via its joint venture with Chesapeake Energy Corp. Dominion reported earlier this year that it is considering applying for DOE permission to export from Cove Point.

Crandell noted that the Marcellus is already making 2.5 Bcf/d. “Over the next several years, Marcellus production could grow to a multiple of today’s level, paced only by infrastructure build-out.” The greatest risk of production curtailment is in Susquehanna and Bradford counties in northeastern Pennsylvania and in Washington, Greene, and Fayette counties in the southwest. “(These) are developing most rapidly and could become glutted if takeaway capacity is not built expediently,” Crandell said.

Meanwhile, where is the excess gas going today? Crandell said 96 Bcf of new storage capacity has been created in New York, West Virginia, Ohio, and Pennsylvania.

New demand

Besides creating new markets abroad for excess Marcellus and other US gas, users’ interest at home is piqued. In the heart of the Marcellus play, Pittsburgh-based United States Steel Corp. is already experiencing sales growth from providing tubulars to gas wellsites.

It is also looking at using more natural gas in its furnaces, reducing its dependence on coke (carbonized coal) as availability of this raw material has become more constrained and expensive and as markets have become more volatile.

“We could realize further benefits from this now-abundant, competitive, and environmentally friendly source of energy,” said John Surma, US Steel chairman and CEO. “This could be as basic as increasing natural gas injection in our blast furnaces to replace costly purchased coke and lower our CO2 emissions.”

It is already injecting more natural gas into its furnaces now, improving its profit structure. To use yet more natural gas, it will have to retrofit furnaces. And this will be worth it, Surma said.

By a 2009 estimate, less than two years into the play, the Marcellus had already exceeded recoverable reserves of eight of the world’s largest gas fields. The estimate keeps growing as producers further prove the shale’s potential and horizontal technology is now being applied to Upper Devonian and Utica shales.

He broke it down this way: Coke may cost $300 to $400 per ton, and natural gas is below $10. Reducing coke used in making one ton of raw steel from 800 lb to, say, 600 lb is a significant profit-margin improvement. The company makes 32 million tons of raw steel a year in North America and Europe.

“There are blast furnaces in the world that go to 400 (lb of coke per ton of raw steel), and we may as well try to get there,” he said. “… It's meaningful. It's a meaningful portion of that total coke load — if you think about it — of 800 pounds per ton of raw steel.”

Among electric power generators, northeastern US coal-switching to natural gas was evident in 2009 and 2010 as gas supply was readily available and considerably cheap, even relative to coal. Crandell said, “Gas demand in power generation has been the main source of growth for Northeast (gas) markets.” Switching back to coal is possible, but power generators will stick with natural gas as long as it’s cheaper, he noted.

And the wet gas the Marcellus gives up is making for an entirely different specialty chemicals game in North America. Containing ethane, propane, butane, and even natural gasoline, the wet gas has captured the attention of US petrochemical manufacturers. The potential is even a leading conversation today in The Dow Chemical Co.’s C-suite.

Andrew Liveris, Dow chairman, president, and CEO, said securing supply of less expensive raw materials is essential to cost competitiveness. “The specialty chemical company graveyard is littered with companies that didn't understand the strategic importance of integration.”

Demand for ethane is almost entirely for making ethylene, which is made into polyethylene or plastic. Ethane for which there is no demand is simply left in the gas stream and sold to customers as extra-Btu natural gas. The producer doesn’t get paid as much for it as it would if the ethane were stripped out.

Getting paid for it

Range Resources aims to get paid for it. And it’s a bundle: In recent years, ethane has been priced at an average of 46% that of the Nymex price for West Texas Intermediate (WTI) crude oil. Simple methane or dry gas: 9%.

US gas producers describe having liquids in their mix these days like this: Even 25% WTI for gas liquids is worth more than 100% Nymex for dry gas.

Range is working on two firm-purchase deals with ethane consumers — Dow on the Gulf Coast and Nova Chemicals Corp. in Sarnia, Ontario — for the ethane it’s making from its wet gas Marcellus acreage to further drive its rate of return from the play.

It’s no small amount of NGLs that Range expects to make. For example, in the liquids-rich window of Range’s leasehold, it appears that the smallest completion type (eight-stage frac, 2,500-ft-lateral) well will make 5 Bcfe, of which 3.6 Bcf is dry gas or methane and 239,000 barrels are NGLs. With a 3,500-ft lateral and 12 frac stages: 6.7 Bcfe or 4.1 Bcf of methane and 425,000 barrels of liquids.

“Maybe we can turn that into 500,000 bbl a well,” Range’s Ventura said, “… Given the huge acreage position we have on the liquids-rich portion of the play, this could be very impactful.”

Across its leasehold, Ventura estimated that Range could make 307 to 463 million bbl of liquids with the small completion scheme. “I would expect the performance could continue to climb with time as we get better and better about what we're doing. So it's not unreasonable to think we'll reach the high end … with 463 million bbl of liquids,” Ventura said.

But the potential for revenue uplift doesn’t stop there – this is the price Range receives when the ethane is left mixed with the methane when put into pipe to market.

“Once we start extracting ethane, it's going to double our liquid yields, so the 463 million bbl becomes 926 million bbl net to Range,” said Ventura. “And then, if we can get better about where we land (our wells) and how we drill and complete, really, you're approaching 1 billion bbl.”

Efforts to monetize the ethane began virtually with Range’s work on the play several years ago, said John Pinkerton, Range chairman and CEO. In time, it has teamed with other wet gas producers to leverage the combined supply power. The prospective buyers are impressed with the figures, he added.

“This is going to be a lot of ethane. … At the end of the day, we'll get gas-plus for the ethane, which is something that we never thought would happen two years ago. We were hoping it would, but now, it's clearly going to happen. … It will have a big impact on our realizations and our margins and, obviously, enhance the intrinsic rate of return,” he said.

Range and midstream operator MarkWest Energy Partners LP, which is the largest gas processor and fractionator in Appalachia, have two plans for getting the ethane to markets upon users’ signatures on firm purchase agreements. In one, “Mariner East,” 50,000 bbl of ethane a day would be piped to Philadelphia and put into Pennsylvania-based pipeline operator Sunoco Logistics Partners LP ships. It can be sold into any market — to Dow and other users on the Gulf Coast, to US Northeast plants, and even abroad.

In the other, “Mariner West,” 65,000 bbl a day would be put in an existing Sunoco Logistics pipeline, modified for ethane export at Vanport, Pa., and sent to Nova Chemicals at Sarnia, the old Lake Huron oil town that hosts a large petrochemical industry. Beginning this summer, MarkWest will be able to recover more than 40,000 bbl per day of ethane from wet Marcellus output and, by mid-2012, 70,000 bbl per day.

Frank Semple, MarkWest chairman, president, and CEO, said of the Marcellus, “This significant shale play is a game changer for natural gas supply in the US.”

Reversing Gulf Coast pipe

A competing ethane export plan is conversion of Spectra Energy’s Texas Eastern pipeline in Pennsylvania and Ohio and El Paso’s Tennessee Gas Pipeline system from Ohio to the Gulf Coast into an ethane line, the Marcellus Ethane Pipeline System (MEPS). It would carry 60,000 bbl of ethane a day to Dow Chemical, ChevronPhillips, and other petrochemical manufacturers whose announcements recently of expanding their ethane demand, primarily on the Gulf Coast, are encouraging, said Doug Foshee, El Paso chairman, president, and CEO.

“Others have estimated that this could result in an additional demand in the Gulf Coast of more than 250,000 bbl a day of ethane,” Foshee said. “… We believe our MEPS project is best positioned to move the large volumes of ethane produced from the Marcellus to the Gulf Coast, and we continue to work … to get this one over the finish line.”

Spectra is a 50/50 partner with El Paso on MEPS, which is an $800 million to $1 billion project. Ebel noted, “Right now, you don't have a way to get the ethane from the Marcellus down to the Gulf Coast. So I think the advantage you have is some pipeline that's not being utilized, which El Paso brings to the table. The Gulf Coast is a 600 or 650 million b/d market. And that's where you want to be taking the ethane.”

Ebel notes too that MEPS is advantaged in that it is expandable to several hundred thousand barrels. “That expandability piece is going to be really valuable,” he said. “That expandability of a pipe … is going to serve them (on the Gulf Coast) better than, say, a marine solution, etc.,” Ebel said.

The big prize to petrochemical makers is that ethane is far cheaper than naphtha feedstock. Pinkerton said, “You have a global economy that's using naphtha. You have this huge push of ‘How do I get off naphtha and get to ethane?’ I think what you see is this global movement to the cheapest feedstock that you can. And you'll do all the ethane that you can.”

On the Gulf Coast, Dow is restarting an existing ethylene cracker and increasing its feedstock flexibility for several other crackers. “But we're not stopping there,” Liveris said. The arrangement with Range “will give us access to the liquids from the Marcellus … and complements the ethane and propane supply contracts that we already have in the Eagle Ford and other shale gas regions.”

Producers are eager to get the product out of the gas stream it is putting in pipe, as shippers can — and are legally required to — reject gas that is too wet. MacKenzie estimates that new liquids-rich production across the US, such as from the Marcellus and Eagle Ford, will make more than 200,000 extra barrels of ethane a day by next year.

Williams Cos. is interested as both a producer and user. It operates a 1.35 billion lb/year olefins cracker at Geismar, La., on the Mississippi River that also makes 90 million lb of polymer-grade propylene. Its olefins team also runs 200 miles of ethane pipeline and a 500 million lb/year propylene splitter.

Armstrong noted that more than 80% of the petrochemicals manufactured in the US use natural gas, while about 60% of olefins produced in the world are made from oil. "When you look at the cost advantage natural gas has over oil, you start to craft a picture of how advantaged the US is because of low-cost gas," he said.

Further experiment

While creating markets for Marcellus dry and wet gas, operators are also working to improve best E&P operating practices. In Bradford County, EOG Resources’ new, proprietary frac scheme, designed specifically for the Marcellus play, was used on the Guinan 2H that IP’d 9 MMcf and on the Hoppaugh 3H that IP’ed 14 MMcf.

Loren Leiker, EOG senior executive vice president, exploration,said, “(It’s) a specific completion technique that's proprietary to EOG and we can't really talk much about the details.” Further shrouding the secret is that, on both wells, EOG has 100% interest. “But we work really hard, gathering the data and analyzing the data, and continue to refine our completion techniques for each play,” Leiker said. “And so they're very specific, and it's working out really well for the company.”

In Westmoreland County, Consol Energy is spacing fracs at between 250 and 300 ft, and it will test tighter in the future. Two recent wells in central Pennsylvania came on, combined, at 15 MMcf/d — remarkable because industry has been skeptical of the productive potential of that region, said Nick DeIuliis, Consol president.

Meanwhile, Ultra Petroleum is at work in improving its wellsite selection and lateral landing. As it went into the play, it ran Schlumberger Ltd.'s EcoScope multi-function LWD tool in its first 18 or so wells, steering it and taking petrophysical data across a 4,300-ft section as opposed to just at one point within the well bore.

This has added some $200,000 to the cost of each well, but it is worth it, said Selvius. “Ultra's in a unique position with our dataset, because it is unlike most others out there. … And we've got a lot of data other operators don't have,” he said.

EQT is experimenting with a new frac-geometry design and has used it in 13 wells. “We continue to see higher IPs per lateral foot treated with this new design,” said Phil Conti, CFO. The five wells to which the new geometry has been applied and that have been online for more than 100 days were making 60% more gas than others.

The company won’t disclose more details on the technique yet but reports that these wells cost an extra $1 million. Steve Schlotterbeck, EQT senior vice president, E&P, said, “While we are clearly seeing higher production rates initially, it’s very important that we get a little longer production history so we can accurately calculate the return we are getting for that extra million dollars (per well).”

Range, while applying a standard lateral and frac to most wells to secure its acreage, is still conducting some experiments too with longer laterals and more frac stages and where the lateral lands in the formation — high, low, or in the middle. “It varies depending on where you are in the play, even where you are within a county, we believe,” Ventura said of the sweet landing spot. “Whether you’re wet or dry is important too.”

Having pioneered the Marcellus play, Ventura noted that Range carried 100% of the initial cost of science. “We're not doing that anymore.” Early on, it and others were building acreage and didn’t share much information.

“At this point, I think companies are more cooperative than they are competitive,” Ventura said. “So not only is Range doing experiments, but other companies out there are drilling laterals up to 9,000 ft and putting a bunch of stages in them. So we can learn not only from our wells but from others.”

Field costs, taxes

In 2008, average horsepower deployed per Marcellus well was some 6,000, according to MacKenzie. Lateral lengths averaged 3,000 ft; frac stages, seven. In 2010, the averages were remarkably different: Wells were put on as much as 30,000 hp; producers pushed lateral lengths to 5,000 ft; and frac stages averaged 15, he said.

Today some operators are taking laterals to 9,000 ft and testing farther. Some 90 rigs are at work in the play this year, and more than 140 are expected to be at work in 2012.

EQT has begun tracking its total lateral lengths and fracs to measure its work rather than just number of wells, since each of its Marcellus wells is more intense than last year’s. By this past April, it had spudded 167 Marcellus horizontals; among those producing into sales, 1,450 frac stages were applied, and another 861 fracs are planned for wells waiting on completion, said Conti.

Operators report experiencing oilfield cost inflation in Appalachia, but not so much more than throughout the Lower 48. John Manzoni, president and CEO, Talisman Energy Inc., said it has long-term contracts for completions work, so its cost there is fairly constant. “But clearly, material costs, diesel, sand, all of those sorts of things have seen some quite significant pressure between the fourth quarter and the first,” he said.

Conti expects further cost inflation next year. A typical 5,300-ft lateral EQT well will cost $6 million-plus. “Most of the money for the Marcellus, at least, is spent on fracing,” he added.

Ultra Petroleum’s well costs in Tioga and Potter counties are averaging $4.3 million, while deeper wells in Clinton and Lycoming counties cost between $6 and $7 million. “Like other operators in the trend, we're experiencing cost pressure on the completion side, but are managing to offset those increases on the drilling and water handling (side),” said Selvius.

Meanwhile, leasing costs are not softening, making the play still costly if seeking to renew leases or capture more. “Frankly, we’ve been waiting for economic circumstances to have caused the lease bonuses to have dropped, though I have to acknowledge that doesn’t really seem to have happened very much,” said Porges.

And a new invoice is on the horizon: a Pennsylvanian type of severance or production tax. Currently, the state doesn’t have an oil and gas severance tax, and legislators are considering an “impact tax.”

“It’s a severance tax disguised as an impact-fee tax,” said Paul Smith, Talisman executive vice president, North American operations. The state’s new governor, Tom Corbett, is opposed to a severance tax but has said he is willing to consider the impact tax. Producers have said they would support a transparent impact fee that is based on their actual activity and with the areas involved being the actual beneficiaries of the proceeds.

“With gas prices where they are today, one needs to be very careful about the imposition of a severance tax with capital mobility being very mobile,” said Smith. “And I think that's the message the governor of Pennsylvania is fully aware of.”

Environmental concerns

Yet more costs are associated with true or false beliefs about how oil and gas is drilled for and produced in Appalachia. When Semple talks about increasing processing and NGL takeaway capacity from the Marcellus, “we are not factoring into our plans any impact on production from the rhetoric, if you will, of fracing technology in particular,” he said.

He believes the industry will get past it, “but it's something that we just need to keep a real focus on.”

Producers have formed the Marcellus Shale Coalition to jointly collaborate with and provide facts about oil and gas drilling to community members, legislators, and regulators. An ongoing matter has been water disposal.

Rex Energy and others are using a closed-loop drilling system and not open pits for disposed mud and cuttings. Solids are being sent to landfills that can handle these. Meanwhile, at press time, Pennsylvania’s Department of Environmental Protection (DEP) suspended disposal of drilling wastewater at 15 facilities that had been permitted to accept it.

Dan Churay, Rex president and CEO, said, “We re-use our frac water multiple times before we ultimately dispose of the remaining flowback. However, until DEP concerns are satisfied, we, along with other members of the Marcellus Shale Coalition, have heeded this request and ceased disposing of any remaining flowback water at these previously permitted wastewater treatment plants.”

Rex is trucking wastewater and injecting it into permitted wells in Ohio. Cost-wise it had been using disposal wells in Ohio for some time anyway, so it’s not seeing a big cost jump because of this, Churay said.

Chevron Corp., which bought Appalachia-based independent Marcellus operator Atlas Energy Inc. earlier this year, noted the new DEP prohibition as well. It was already Atlas' and, now, Chevron's plan to discontinue disposal at Pennsylvania facilities by year-end 2011, said Gary Luquette, president, Chevron North American E&P Co. Like Rex, it will put wastewater into disposal wells in the future.

Entry into Marcellus-shale acreage via purchase has topped $7,000/acre; via joint venture, more than $14,000. (Source: Jefferies & Co. Inc.)

DeIuliis said, “More regulation, I think, is going to be the norm, to say the least. And it's going to be across a range of issues with regards to the Marcellus from water sourcing, water discharge, and standards of water discharge to where the water can be discharged and stream-crossing permit issues for pipelines and gathering lines. And just about everything in between.

“So it's coming. And we are prepared to partner with the regulatory agencies on the gas side, just like we've done historically on the coal side, and the industry is going to need to be in a position to do so as well.”

Production from some of Consol’s wells is being curtailed while the company waits to combine the full output potential of several wells that so fewer stream-crossing permits are needed to get production to big pipe, thus to processing and users.

Crandell said, “Despite concerns about drilling in some states — notably, New York — and a few public spats about drilling in Pennsylvania, in aggregate, drilling in the broader Marcellus should result in production growth for some time.”

Stacking shales

Additional horizontal experimentation in the Appalachian gas basin that is under way is into the Upper Devonian shale, which is shallower than the Marcellus, and into the Utica, which is deeper.

Rex Energy plans a first Utica test well in July and is drilling its first horizontal test of the Upper Devonian, through which it has drilled some 20 times now to reach Marcellus. Pat McKinney, Rex executive vice president and COO, said, “Our geologists feel really good about what they're seeing as far as the (Upper Devonian) thickness and extent out there (in our core area).”

Range brought two Upper Devonian horizontals online earlier this year, picking locations more than five miles apart. The first IP’d 5.1 MMcf; the second, a constrained 2.5 MMcf, consisting of 1.9 MMcf of dry gas and 91 barrels of NGLs. The average IP was 3.8 MMcfe.

The second well has a flatter decline rate and higher EUR than the first, said Ventura. “For our first two horizontal wells in the Upper Devonian shale, we're encouraged about the results and the potential it has for unlocking the … resource potential,” he said.

It wasn’t until Range’s seventh Marcellus horizontal that it reached an average IP of 3.8 million, he aded. Reserves in the Upper Devonian appear to be 2.5 to 3.5 Bcfe per well. “This is significantly ahead of where we were in the Marcellus at this point in time,” he said.

Range plans three or so additional Upper Devonian tests this year. Early indications are that the shale will be wet where the Marcellus is wet; dry where the Marcellus is dry. Gas in place should mimic the Marcellus too in acreage where both are prospective, Ventura said.

“If, in a particular area, gas in place is 100 Bcf per section in the Marcellus, the gas in place in the Upper Devonian in aggregate would be 100 Bcf. So it about doubles what you have in that area,” he said.

The company seeks more data on the Upper Devonian. “But we know we have hydrocarbon,” Ventura said. “We know we have wet gas. We know it can produce commercial rates even after our first two tries.”

Range’s early Marcellus wells tested various lateral landing depths. A first well IP’d a discouraging 20,000 cf, but another made 1 MMcf and another made 3.6MMcf. “Now, in that same area, we're getting 10 to 15 MMcf. Our best well was 26 MMcf/d. And that's just moving where you land the well in the section and has nothing to do with lateral length or frac stages,” Ventura said.

“I think the same thing will be true of Upper Devonian.”

In the Utica, Range’s next horizontal test will be later this year, and a third is planned for early 2012. It is expecting other operators’ work on Marcellus, Upper Devonian, and Utica to further prove up its own acreage. Very few wells have been drilled to Utica, as it is deeper than Marcellus, while thousands of wells have been drilled through Upper Devonian on their way to Marcellus and other formations.

“If you go way to the east, you're going to lose the Utica (window),” Ventura said. “If you go far west, you'll lose the Marcellus and Upper Devonian.” The economically productive Upper Devonian, Marcellus, and Utica appear to be stacked in southwestern Pennsylvania, the heart of the Marcellus play and Range’s core area, Ventura said. “So a lot of our acreage in the southwest could have stacked pay potential in all three horizons.”

Ultra Petroleum Corp. is holding off on trying the Utica. Bill Picquet, Ultra senior vice president, operations, said, “The Utica is active under our acreage. It's gas-bearing, and it's got the kind of look you like to see, but it's deep. It's 11,000 ft to probably as deep as 14,500 or 15,000 ft in the southern part. It's out there.

“(But) you need better than $4 gas to make the Utica.”

EQT Corp. has drilled one Upper Devonian in western Virginia and will drill one this year in southwestern Pennsylvania. Otherwise, said Conti, “Our plans for the Utica right now are to sit tight and watch what our competitors are doing and, if that ends up being the next big thing, we’ll be right there with them.”