Bob "Coach" Rikeman comes by his nickname honestly. He coached college baseball for 25 years and worked as an assistant scout for the Chicago White Sox during that career. But now, thanks to the epic rise of the Marcellus Shale as one of the largest gas fields in the world, Rikeman is the unlikely vice president of logistics for newly public exploration and production (E&P) company Rice Energy Inc., a position he’s held since 2010—though he never worked a day in the oil patch previously.

You see, Rikeman was the head baseball coach at Rollins College in central Florida to two of the Rice brothers who founded the company, taking the team to the college World Series in 2004. And later, when they recruited him to handle field operations for their budding Marcellus endeavor, they surreptitiously canceled his return flight after proudly showing off their one rig site in southwestern Pennsylvania at the time. “I haven’t been back since,” Rikeman said, “and I’ve loved every minute of it.”

On this day, standing on an Appalachian hillside in the driving rain of a sweeping storm that would capture national attention, Rikeman watches over a hydraulic stimulation of the Alpha Unit 2-7H well in Greene County, just miles from the West Virginia border. This is the third of four being simultaneously zipper fracked on the pad, with each completion stage done in sequence down the line. The well, like the others lined up beside it, features a 9,000-foot long lateral with 52 stages, a detail Rikeman now understands wholly following his on-the-job, hands-on immersion. The first four wells on the pad, already in production, each aver- aged 9 million cubic feet per day (MMcf/d) over the first six months of production.

“These are very good wells,” Rikeman said. “I haven’t seen a bad well yet. We’d be disappointed if it wasn’t 20 million.”

Prolific wells combined with improving efficiencies result in steadily growing production even as rigs trend down.

Good wells remain the norm in the Marcellus Shale. The Marcellus, a natural gas formation sweeping diagonally across Pennsylvania and into West Virginia, has emerged as one of the world’s largest natural gas reservoirs, with an estimated 410 trillion cubic feet (Tcf) of recoverable resource, according to the Energy Information Administration. Its production curve has skyrocketed, with 14.5 Bcf of gas being produced by the play today, surpassing all other U.S. gas plays and in spite of suppressed gas prices nationwide. Favorable well economics provide profits at lower breakeven prices.

The success of the Marcellus, though, creates its own challenges. Ballooning production has swamped existing pipeline capacity and midstream providers are struggling to keep up with new projects. During the summer, northeastern gas markets are oversupplied, creating significant spot pricing differentials to Henry Hub and prompting pipelines that once imported gas to reverse to new markets. During the winter, Northeast demand exceeds pipe capacity, resulting in price spikes—if the gas can reach the consumer.

Nonetheless, the proof is in the production. “The Marcellus Shale will be the biggest driver of U.S. dry gas production over the next several years, adding 3 Bcf/d in 2014, and another 2 Bcf/d in 2015, by which time it will account for close to one-fourth of total domestic volumes,” Morningstar energy sector strategist Mark Hanson said in a February report.

“In short, the growth of the Marcellus over the next several years is nothing short of astounding. It is the undisputed champion of U.S. natural gas production.”

Although Marcellus rigs are down about a third since 2011, wells drilled per rig are almost double in that time frame. The Marcellus covers an area stretching from central New York state through much of West Virginia, with most operator activity currently in far northeastern and far southwestern Pennsylvania.

Measured growth

One trillion cubic feet of gas. That is the cumulative quantity of natural gas that Cabot Oil & Gas Corp. has thus far produced from the Marcellus Shale, all in six years with no more than six rigs. “That cumulative production in that short a period of time is quite remarkable,” noted Cabot CEO Dan Dinges. “Our production today is about 1.5 Bcf [a day], and we continue to utilize six rigs. We should approach 2 Bcf per day of production at year-end 2014.”

That’s about 10% of total volumes flowing from the basin, and it’s almost as if Cabot can’t help itself. Every year since it began producing here, it has owned the majority position of the top 20 most prolific wells by cumulative production, per Pennsylvania Department of Environmental Protection well data. In 2013, Cabot claimed 14 of the top 20 wells; 17 of 20 in the latter six months, with the best 13 of the entire Marcellus.

“During 2013, two wells we turned in line had EURs [estimated ultimate recoveries] over 30 Bcf,” said Dinges. “We have 16 wells in 2013 that are over 20 Bcf.”

Dinges trips down memory lane, recounting one three-well pad in the last year that had an IP rate near 80 MMcf/d, another at 60 million. “Very prolific wells,” he said.

This smorgasbord of resource begins with good rock. Houston-based Cabot holds 200,000 acres in desirable Susquehanna County, in northeastern Pennsylvania, where it began leasing in 2005 when only five wells had been drilled in the history of the county. To date, Cabot alone has drilled 290 horizontal Marcellus wells. Its Marcellus program showed a 70% production growth rate last year (measured against a 54% total company growth) with 95 wells drilled in 2013.

“We have prolific rock up there and do not need many rigs to be able to grow our production significantly,” Dinges said. That phenomenon has created what he deems a high-class problem. “We don’t need many rigs to grow production and, consequently, we don’t capture as much primary term acreage annually compared to some other areas of the play.”

Efficiency gains are the focus, with just 25% of Cabot's program last year focused on pads of five or more wells. However, the company plans 60% of its program to be multiwell pads this year. Even before this change, Cabot already measured finding-and-development costs of 40 cents/Mcf of gas. Gaining the expected savings of $600,000 per well from pad drilling will provide continued improvement, he said.

Cabot drilled its first 10-well pad during 2013, turning it online in November with 170 stages of completion. “We saw a peak rate over 200 MMcf/d, and a 30-day average of 170 MMcf/d.” That pad tested spacing down to 500 feet between wells, from 1,000 feet.

While Cabot’s hydraulic fracture stimulation recipe is consistent, Dinges notes it is ever evolving. Like others, the company is experimenting with reduced cluster spacing of 150 and 175 feet, compared with 400 feet in earlier wells. “We’re encouraged by what we’re seeing,” he said. Even before reducing cluster spacing, Cabot posts a 3.6 Bcf EUR per thousand feet of spacing, the highest in the Marcellus, per Dinges.

Cabot, though, like all operators in the play, is dealing with full pipes and volatile pricing differentials, prompting Dinges to label this year and next as “somewhat challenged” for finding transportation and favorable markets. “The last couple of years we have managed our growth because of infrastructure challenges,” he said.

Still, measured growth rates of 35% in 2014 and 25% in 2015 at the midpoint of total company production guidance is “significant in absolute volumes” against a potential 2 Bcf/d exit rate this year. And although Cabot is short of having firm transport and sales for the total anticipated flow, “We are comfortable we’ll be able to market that gas. We are confident we can grow our production levels in 2014 and beyond.”

The inflection point to bust the bottleneck will come when Williams’ Constitution Pipeline comes online, which is expected in late 2015. Cabot holds 500 MMcf/d firm on the line, and has another 850 MMcf/d firm on Transco’s Atlantic Sunrise, due in 2017. When that project comes online, Cabot is ready and waiting with firm sales contracts to Northeast utility Washington Gas & Light for 500 MMcf/d, and a 20-year supply deal with Japanese conglomerate Sumitomo via the Cove Point LNG terminal for 350 MMcf/d.

In the meantime, takeaway constraints basinwide have created wide-ranging price differentials in various spot markets, on average 75 to 80 cents under Nymex to Cabot in April. Even so, economics remain robust. Cabot realizes 100% returns on $3 gas; 200% at $4. It is planning 110 new Marcellus wells in 2014 on an approximate $900 million capex investment.

“Those returns are in the top of the class,” said Dinges. “We’re going to continue to move an ever-growing, large volume of gas to the marketplace in a prudent manner, and deliver very good returns.”

Home-run wells

Formed in 2007, Rice Energy just went public in January as the second-largest independent E&P IPO ever with a market cap currently of $4 billion. The Canonsburg, Pa.-based company’s assets are focused in Washington and Greene counties in southwestern Pennsylvania, in the Marcellus dry gas window. There, it is currently producing some 300 MMcf/d, with another footprint in the Utica play across the border in Ohio. The story of Rice, formed by three brothers with a top age of 33, belies oil and gas startup models.

“We’re from the heart of oil and gas country—Boston,” quipped Rice Energy CEO Dan Rice. “And we’re relatively young.”

Dan, the oldest of the three, has a background in finance. He worked at Transocean Ltd. and Tudor, Pickering, Holt & Co. before joining his brothers. Toby, president and COO, and who originally formed the entity, is a petroleum engineer by trade who started his own hydraulic fracturing consulting company after beginning a master’s program at Texas A&M University. Derek, vice president of exploration and geology and a petroleum geologist, joined his brothers immediately after graduation. Toby and Derek played ball for Coach.

It was their dad, a Boston energy portfolio manager, who persuaded them to get into the oil and gas business and seeded the budding startup.

“It was completely grassroots,” Rice said, with no private-equity sponsoring. The boys, based out of Toby’s Pittsburgh apartment in the early days, began buying mom-and-pop parcels of what they believed to be a fantastic emerging play, and built it to nearly 50,000 acres, with a similar amount in Ohio. Now they employ 200 people. “We didn’t have any preconceived notions of how to do things based on years of running an oil and gas business. We determined to let data drive our decisions.”

Hiring smart people who can interpret information and make implementations in the field has been critical to the company's success, he said. “We capture data at the ground level, process it, and make decisions in almost-real time. Information flows to decision makers quickly. Having a flat organization that leverages technology is critical to us.”

Quality over quantity is also a mantra. “We try our best to make sure that every single well we drill is a home run.”

The company runs only two horizontal rigs in the Marcellus, along with two top-hole rigs, preferring to stay lean. “We don’t want to run 20 rigs to grow production for production’s sake. We want to drill the most economic wells, and production becomes a byproduct of having an optimal process in place.”

For three years, Rice Energy focused on the science of drilling Marcellus wells, before shifting to pad drilling. Rice logs each well’s vertical section, and as a result of its findings, the company targets the lateral wellbore into a narrow three- to five-foot slice of the Marcellus with the highest total organic content, porosity and permeability. “The geosteerer can’t sleep— he’s awake 24 hours a day” while drilling in the zone, said Rice.

“We took our time optimizing our reserve recoveries before we turned our attention to cost cutting.”

Results tell the tale. Rice holds the record in the play for the most production with the fewest number of wells, 44 at the end of the first-quarter. Recent wells have averaged almost 12 MMcf/d over 90 days on restricted choke, and are designed to top out at 2 MMcf/d per 1,000 foot of lateral at peak rate. While earlier wells tested as high as 40 MMcf/d peak rate, “We don’t let them rip,” Rice said. “We’re not about IPs; we’re about long-term production.”

After 500 days online, the Mono 4H in Washington County still averaged more than 11 MMcf/d, and produced an accumulated 5.4 Bcf on a 6,000-foot lateral, the largest producing well in Washington County by double other peers.

After 180 days, two 9,000-foot lateral wells on the Thunder pad in Greene County averaged 12 MMcf/d. Three wells on the Hulk pad in Washington County, also with 9,000-foot laterals, flowed steady on choke at 16 MMcf/d for their first five months. “I think that’s illustrative of what these longer laterals will do,” he said.

Rice models EURs of 12 Bcf for a 6,000-foot lateral well; 16 Bcf for an 8,000, and 20 for 10,000 feet. “So we’re getting darn good recoveries.” Costs for the recent 9,000-foot laterals were under $11 million each, for returns of 80% to 100% at $4 gas.

Production is expected to double this year, he said, “and there’s a decent likelihood it could double again in 2015.” The company’s 2014 Marcellus budget is $430 million.

Rice also owns its own gathering system, an organic buildout that originated by happenstance when it needed to make a one-mile connection to a transportation line from its first well. It grew from there. Not only does controlling the gathering system assure the flow of its product, “it significantly reduces our operating cost,” Rice said.

“A 20- to 40-cent savings just by virtue of not incurring a gathering fee is pretty critical. It also allows us to build pipelines to the transmission lines on which we want to pick up firm transportation.”

Working the middle

Recognizing that the northeastern and southwestern corners of Pennsylvania receive the Marcellus “core” label, Seneca Resources president Matt Cabell likes the middle ground just fine. Seneca, the E&P division of National Fuel Gas Co., holds 780,000 acres—much of it fee simple—along the Marcellus arc that cuts through the central-western region of the state.

“People have written off the central part of the play because there hasn’t been a lot of development there. But, frankly, I think the results we achieved in 2013 are proving we’re going to have a big, broad area of highly economic wells in that part of the play,” said Cabell. “That’s why we’re focused on it.”

Based in Houston, Seneca divides its large Marcellus portfolio into two regions. Its eastern development area consists of 60,000 leased acres largely in Lycoming and Tioga counties, where it has focused activity with two rigs drilling 109 wells over the past two years. “Our Tioga County acreage has been good; our Lycoming County acreage has been outstanding,” he said. “We’ve had many wells come on at rates higher than 20 MMcf/d.”

In fact, its most recent pad featuring seven wells in Lycoming ranged from 17 to 22 MMcf/d IP. Using Pennsylvania DEP data, “our production rates in Lycoming County are essentially double the next best operator.”

Seneca’s average EURs in Lycoming stand at 11.5 Bcf per well, based on overall average IPs of 16 MMcf/d, but could trend up on newer wells. The breakeven price is a strong $2.80, third best in the play, based on ITG IR data. Tioga is noteworthy as well, at 5 to 8 Bcf EUR per well, and a breakeven of $3.65.

“Over the course of the next several years, we’ll fully develop our Marcellus potential in Lycoming and Tioga,” Cabell said, with one rig running in the play.

Seneca has shifted from one rig to two in its western development area, where it holds the majority of its acreage. Its 720,000 fee acres stretch in contiguous blocks from Warren and McKean counties in the north to Venango and Jefferson south. However, Cabell identifies 200,000 acres along a southwest-to-northeast axis from Jefferson to McKean counties as de-risked and economic at natural gas prices from $2.80 to $3.80 per Mcf.

“It looks like we’re getting wells similar to those in Tioga County,” he said. In that Tier 1 area, “We think we will consistently achieve 6 to 8 Bcf EURs, and strong economic results because of it.” The company estimates some 2,000 drilling locations here at 1,000-foot spacing.

The two rigs are focused on the Clermont and Rich Valley region straddling the Elk and Cameron counties line and are in full development mode, drilling on six- to 10-well pads. Recent seven-day IP rates range from 5 to 10 MMcf/d.

Seneca is testing reduced cluster spacing in newer wells and likes the results. While earlier wells were designed with 300-foot stages, Clermont 9H in Elk County cut the distance in half to 150 feet per stage, and the 10H split the difference at 240 feet. The 9H peaked at 11.4 MMcf/d with an 8.6 Bcf EUR, and the 10H at 7.3 MMcf/d with a 6.6 Bcf EUR.

“We saw a significant difference between the two wells; it easily justifies the extra cost. We’re not ready to say we’re doing it everywhere now, but we are doing it in most places.”

An averaged realized pricing differential of 50 to 60 cents discount to Nymex, when factoring firm sales and spot sales together, has prompted Seneca to aggressively pursue firm sales, followed by locking in firm transport agreements. Prices are “highly volatile,” he said. “We have some days much better than that, and others much worse."

Although the company hedges its production, the hedge price locked into Nymex is just not that relevant, he noted. “If the basis differential is the area of un- certainty, you haven’t really solved the problem unless you have transportation and/or firm sales.”

Currently, Seneca is producing 400 MMcf/d in Appalachia and projects a 2014 exit rate above 500 MMcf/d. It has firm sales locked up through fiscal 2014 (through September) for 340 MMcf/d, and 280 MMcf/d firmed through fiscal 2015, with more being added. Beginning in late 2015, the company will find relief with 170 MMcf/d committed to TGP’s Niagara Expansion project, and 190 MMcf/d to Transco’s Atlantic Sunrise in 2017.

“Marcellus production is growing while the rest of the country is flat to shrinking. Until those pipes are built, we’re going to be looking at discounts to Nymex.”

For now, Seneca is waiting on more certainty on pricing before adding to the rig count, he said. “We can predict what Nymex is going to be in two years, but we don’t know what basis differential we’re going to get. It’s possible it might get worse. That’s why it’s important to have firm transportation.”

With an estimated $500-million fiscal 2014 budget, Seneca will hold steady at three rigs until pricing uncertainty is resolved, but wouldn’t reduce rig count short of a “meaningful reduction” in prices. On the flip side, “we’re going to ramp up when we see realized pricing above $4 per Mcf,” he said.

“The Marcellus is going to be the most important gas play in North America for the foreseeable future. The results are superior to anywhere else people are drilling for dry gas. We have decades of drilling to do.”

Focused on gas

A 150-year-old company founded on coal mining, Consol Energy Inc. is shifting strongly to being a natural gas-focused company following the sale of five of its mines in late 2013. With positions in both the Utica and Marcellus shales, Consol aims to grow its natural gas production some 30% this year and each year through 2016. Out of the Marcellus, however, it expects production to ramp by 87% year-over-year in 2014, even while holding the rig count steady at eight through the year.

“We’ve had some fantastic drilling results,” said Tim Dugan, Consol COO of its E&P division. “Now it’s about consistently repeating those results.”

Dugan joined Consol in January, a veteran of Chesapeake Energy Corp., EQT Corp. and Cabot, to lead the company’s growth push in natural gas.

Consol, based in Canonsburg, Pa., holds 446,000 net Marcellus acres in southwestern Pennsylvania and West Virginia, and drilled 45 operated Marcellus shale wells in 2013. About 80% of its Marcellus portfolio is in a 50/50 joint venture with Noble Energy, in which Noble operates wet gas wells west of a demarcation line and Consol operates dry gas wells east of the line.

In its operated dry gas region of the Marcellus, Consol is running four rigs: two in Greene County in the southwestern Pennsylvania corner; one in Westmoreland County in central Pennsylvania; and another in the Barbour/Lewis/Upshur counties vicinity in West Virginia.

Currently, Consol concentrates the majority of its attention in southwestern Pennsylvania, where it plans 46 wells this year and is testing enhanced recovery techniques. “We’re seeing EURs just over 2 Bcf per thousand foot of lateral here,” Dugan said, on wells averaging 6,600-foot laterals. However, seven wells drilled in 2014 have averaged 8,900-foot laterals, revealing an upward trend.

“We try to extend laterals as far as we can where the land allows."

Utilizing reduced cluster spacing and shorter stage lengths (SSLs) on 13 tests in 2013 boosted results. “We’ve gone from 300-foot stages and 60-foot cluster spacing to 150 stages and 30-foot clusters,” Dugan said. “We’ve seen good results. We’re seeing a 30% to 40% increase in IPs,” with average peak IPs improving from 8.4 MMcf/d to 12 MMcf/d, “and about a 15% to 20% increase in EURs.” The design costs an extra $1.2 million to a 6,000-foot-lateral well, pushing costs above $6 million total.

Going north, EURs in central Pennsylvania stand at 1.55 Bcf per thousand foot of lateral, and 1.75 Bcf southward in West Virginia, “but we haven’t done as much reduced cluster spacing and SSL there,” Dugan said.

The company plans 39 of these enhanced wells during first-half 2014, mostly on its southwestern Pennsylvania wells, and will test the concept in its central Pennsylvania and West Virginia regions. “We expect that we’ll see similar results and that it will become the standard everywhere.”

Results are robust on its nonoperated wet gas parcel as well. Two recent pads, the West Fin 3 with four wells and West Fin 6 with eight wells in Marshall County, W. Va, “are some of the best wells to date,” said Dugan, with rates in excess of 10 MMcf/d on some wells.

Current type curves here in the West Virginia panhandle reflect EURs of 1.75 Bcf per thousand lateral foot, but “we fully expect that number to go up. We’re going to bring on quite a few wells over the next couple of months and expect more good results.”

Notably, Consol has acquired rights to drill on the Pittsburgh airport and is now building the first of six pads to drill 45 wells on 86-acre spacing. The first well should spud in August. Dugan estimates the company’s Marcellus recoverable resource potential on the airport at 600 Bcf from the Marcellus and another 400 Bcf from the Upper Devonian.

Combined, Consol and Noble project drilling 181 Marcellus wells this year.

And with 1.3 Bcf/d in transport commitments, Dugan said Consol is long on firm for 18 to 24 months.

“We’re not tied to one pipeline,” he said, which adds to the company’s offtake flexibility. Guiding production growth of 30% this year and next, “We’re very comfortable that we’re in good shape over the next couple of years.”

Beyond that, looking at new capacity coming online, he said the Marcellus is well-positioned. “Of all the unconventional plays in the U.S., the Marcellus is set up the best to expand and grow. We’re just getting started.”

Doubling, and doubling again

One of the early movers in the Marcellus, over the past seven years privately held Chief Oil & Gas LLC has high-graded its portfolio from 600,000 gross acres to 210,000 acres, monetizing the rest, and its focus is now on operating in the northeastern Pennsylvania counties of Susquehanna, Bradford, Wyoming and Sullivan. After carving out sales to Chevron Corp. and Exco Resources Inc., that acreage figure now includes a $500-million deal for acreage and producing wells in which Chief had working interest. It acquired MKR Holdings LLC from Chesapeake Appalachia LLC in late 2013.

The company is expanding, said Chief's senior vice president of operations Sam Fragale.

“We’re interested in additional bolt-on opportunities as well as on-the-ground leasing,” Fragale said. “We want to acquire additional acreage in this area and develop it over the long term.”

Running four horizontal and two top-hole rigs today, Chief drilled around 50 wells last year, with up to 90 planned in 2014. Northern Wyoming and Susquehanna counties currently receive the most activity, with Bradford and northern Sullivan in line behind.

“We’re seeing great success in northeastern Pennsylvania. We’ve had some very good results,” he said, referencing select wells that have had IP rates above 25 MMcf/d.

Last year Chief doubled its production volumes, from 200 MMcf/d at the end of 2012 to 400 MMcf/d at year-end 2013. In 2014, “we hope to more than double production again,” as Chief has already crossed the milestone of half a billion cubic feet of production per day.

As expected, Susquehanna County “is one of our better areas,” he confirmed, but emphasized other operating areas parallel those results. Chief well EURs range from 6 to 15 Bcf. Typical lateral lengths extend from 4,500 to 5,500 feet but have reached up to 8,500 feet.

Step changes over the past couple of years with reduced stage spacing from 400 feet per stage to 200 feet have resulted in 20% to 30% higher IPs, about the same for EURs. At $6.8 million for a 4,500-foot-lateral well, Fragale calculates internal rates of return up to 75%.

The company is moving to more pad drilling this year and expects further cost efficiencies. “We’re laying out anywhere between six to 12 wells on a pad where possible, and we’re fully developing them from the start.” For older pads with a single well, “we’re coming back and drilling out the rest of those pads.” One thousand-foot spacing between laterals is the norm.

With the fast-ramping production profile, Fragale indicated the company was "pretty well situated" regarding long-haul takeaway capacity, but getting new wells attached to gathering lines was more of a near-term challenge. “We’re moving all of our gas right now, but we have experienced some pipeline constraints on the gathering system we’re working through so we can get that gas on the grid.”

Aside from that, “we’re where we want to be with the production.” The company is an anchor shipper for the upcoming Atlantic Sunrise pipeline.

Chief expects to spend nearly $250 million in net capex this year for its share of development costs.

With Chief’s history of building to sell, might its Marcellus portfolio be ripe for sale? “I don’t see that in the near future,” Fragale said. “We’re committed to the area; this will be a legacy asset for Chief Oil & Gas.”