In the push to liquids, remarkably the smallest U.S. producers have the greatest advantage in affecting their cash flow from higher-margin oil, which was trading at some 26 times that of natural gas on Nymex at press time.

"A company our size, we can scale up pretty quickly, whereas, for a bigger company, it's harder to move the needle," says Rob Turnham, president and chief operating officer of Goodrich Petroleum Corp. "We can see the results flow through the income statement quite rapidly."

Historically a gassy Gulf Coast player, Goodrich moved into East Texas and North Louisiana in the late 1990s and early 2000s and now holds some 200,000 net acres there. In time, it came to produce 98% dry gas. More recently, the Houston-based, small-cap E&P gained a position in the liquids-rich Eagle Ford play in South Texas.

"It's so valuable to have Eagle Ford acreage right now, to be able to flip the switch and get much oilier very quickly," Turnham says.

Goodrich is focusing 62% of its $235-million 2011 drilling budget on oil-rich acreage in the western window of the Eagle Ford play in LaSalle and Frio counties. "It is not only our operations area that is most prospective for oil, but it carries the most running room and the ability to scale up our program and have material production growth."

Goodrich Petroleum Corp. expects its oil/gas mix to move from about 2% oil in third-quarter 2010 to average 15% this year, at the current oil price throwing off 40% of 2011 revenues, notes president and chief operating officer Rob Turnham.

Its first oily Eagle Ford well, drilled in 2010, came in as a huge gas producer, instead. Turnham says that's not happened again. "It looks like we cut a fault in the horizontal portion of our wellbore and we're capturing some gas from below. We've not seen that again in all the wells we've drilled since. The rest of the wells have come in at 85% to 95% oil."

Its next well, with a 6,000-foot lateral and 20 frac stages, had 24-hour initial production (IP) of more than 1,000 barrels of oil and, overall, makes 95% oil. Wells to date—all in the southern two-thirds of Goodrich's acreage—have had IPs of between 500 and 1,000 barrels.

"That is more indicative of the types of wells we expect to drill going forward. We're looking at a 75% rate of return now, based on an $8-million well cost and 475,000 barrels equivalent EUR (estimated ultimate recovery). That's 80% oil too, so that's where we're concentrating our efforts in 2011."

The other oily area getting capex love from Goodrich in 2011 is its horizontal Taylor sand play in the Cotton Valley in Rusk County, East Texas, in South Henderson Field. Goodrich has 6% of its drilling budget planned for it. There, wells make 25 to 40 barrels of oil per 1 million cubic feet (MMcf) of gas. And the gas volume isn't bad, either—10 MMcf a day. "So, it's a very economic play," Turnham says.

Goodrich has some 50 net locations to drill there, but its larger target is its 550 gross, 400 net, locations on its Eagle Ford acreage, where it has two rigs running.

With that and the Taylor sand work, the company expects its oil/gas mix to move from about 2% oil in third-quarter 2010 to average 15% this year. More important, Turnham notes, is that, at the current price of oil, this 15% of oil production will throw off 40% of the company's 2011 revenues.

One of its rigs at work in the Eagle Ford acreage is drilling from a three-well pad, cutting costs and overall drilling-cycle time and making consistent results. The savings are $500,000 per well, he says.

The rig shifts to making a second, and then a third, hole in about six to 10 hours; moving a rig to another location takes about five days. Once all three holes are made, fracturing is back to back. "You're reducing the number of days you're cycling these wells, so your production volumes will grow faster because you're drilling wells quicker."

The second rig Goodrich has at work is moving around, continuing to delineate its 55,000 gross, 40,000 net, acres; this and the first will make 24 gross, 18 net, holes this year. Turnham expects to ultimately accelerate work in the play, adding a third and possibly a fourth rig later this year.

"The play is working. We've spent a good bit of our time spreading wells out, de-risking acreage, and now we're coming back in a much more development-oriented mode."

Meanwhile, in its Eagle Ford and other holdings, Goodrich is under no pressure to drill. Its primary Eagle Ford lease term is two to 12 years and each carries a "continuous drilling" provision in which the term is pushed as long as the company spuds a next well within 120 days. The same holds true for its gassy Haynesville acreage. "The provision helps the royalty owner too, so you're not producing at a time when gas prices are low."

Financially, the company is well powdered. Its recent $275-million bond offering cleared its bank debt. It has $111 million of cash on hand and an undrawn credit facility with a $225-million borrowing base. "We have plenty of capital to execute and the cash-flow growth you will see from drilling these profitable wells is pretty dramatic."

Acquisitions are possible. "We continue to look," he says. "Certainly something around our Eagle Ford acreage would be good right now. But we've been early movers in our plays where our cost is extremely low. If we can find bits and pieces that are very complementary to our existing acreage, we will do that as long as the price is reasonable."

Niobrara, Permian oil

PDC Energy Inc. is also unrushed in holding its gassy acreage as it focuses greater capex on the oil-rich portion of its portfolio. In fact, it isn't rushed in its oily portfolio, either.

"We are fortunate that, when you look at our entire acreage position as a company, the only acreage that is not held by production is only a small portion outside the Wattenberg Field," says Rick McCullough, chairman and chief executive officer.

Rick McCullough, chairman and chief executive of PDC Energy Inc., will spend 80% of the company's 2011 capex in the Niobrara oil play and the Permian Basin. PDC picked up some 13,000 acres in the Wolfberry play.

To the Niobrara oil play in Colorado's Denver-Julesburg Basin and to West Texas' Permian Basin, then.

The Denver-based, small-cap will spend 80% of its 2011 capex in those two areas. In the Niobrara in the northeastern Wattenberg Field, its vertical wells—which hold most of its acreage there by production from Codell, Niobrara and the J sand—have historically made some 55% oil and gas liquids. "We're expecting a little more oil in the mix as we drill horizontally in the Niobrara, probably another 10% higher," McCullough says.

Larger-cap, Houston-based Noble Energy Corp., which has drilled more than 20 horizontals into Niobrara now, is a neighbor of PDC's in the Wattenberg area. "We've been fortunate to be able to wait and watch Noble's exploration because all of our acreage is held by production," McCullough notes. "We've been very encouraged by their results, so we've just begun our own exploration testing."

The company plans to invest 60% of its $233-million 2011 capex in Wattenberg, including 14 new, horizontal Niobrara wells at an estimated cost of $4.2 million each. It completed its first in November, making an IP of 625 barrels of oil equivalent (BOE) and a first-30-day average of 310 BOE per day. Well design is for an average lateral length of some 4,000 feet and frac stages numbering 15.

Noble revised its EUR to 310,000 BOE per Niobrara well recently. "We're still using 290,000 in our estimates, so there may be some additional upside once we begin testing our acreage."

Also encouraging and of help to PDC is the fact that some 1,500 vertical holes have been made in the past in PDC's leasehold. "That gives us good production history, reserve performance and geologic control as we delineate our horizontal opportunities," says Bart Brookman, senior vice president, E&P.

While PDC already held a position in the hot new horizontal Niobrara, its vertical Wolfberry play in the Permian is a more recent strategic move. There, it targets Wolfcamp and Spra­berry formations at about 8,500 feet on the fringes of a plateau where operators are completing both formations in a formation-transition-zone area.

"When natural gas prices collapsed in 2009, we mapped out a strategy of a push to oil- and liquids-rich plays," McCullough says. The team looked at 20 to 25 basins. "The Wolfberry was selected as our No. 1 choice. It's similar in completions and drilling to what Bart and his team have been doing in the Wattenberg for a number of years."

The oil offering is attractive, and the fact that additional zones in the hole are productive as well reduces economic risk while potentially increasing profitability, McCullough says.

PDC picked up some 13,000 acres there in two deals last year, carrying 240 drilling locations on 40-acre spacing. The play will get 20% of its capex attention this year. "We think we can probably down-space that play eventually. We are off to a very good start with some of the initial drilling results."

The first two Wolfberry wells had peak production of 270 BOE per day, about 85% oil. Another made additional IP of 200 BOE from the Strawn zone; another, 100 BOE from the Bend. The company has one rig at work at the leasehold now and may add a second later this year, McCullough says. At press time, it was working on its 11th well.

Brookman says, "We've been very happy with our drill times, and early production results." Production and reserves booked from zones other than Wolfcamp and Spraberry are bonuses, he adds. "These are add-ons to our acquisition metrics. The evaluations we did (in the data room) were primarily around the Wolfberry, so we feel really pleased with these reserves that we're adding on top of the Wolfberry."

Bart Brookman, senior vice president, E&P, says the company is "very happy with our drill times, and early production results."

The wells cost some $1.75 million each, for a Wolfberry completion only, making a 40% rate of return at today's oil price, McCullough adds. "And, the additional capital is only about $100,000 to get to these deeper zones. We haven't calculated rate of return on these dual-completed wells, but suffice it to say that it will be substantially higher than 40%."

Begun as an operator of drilling partnerships, the company has been almost entirely a gas player in Appalachia and in the Antrim shale in Michigan. In the late 1990s, it added the vertical Wattenberg to its portfolio and, until adding the Permian to its holdings last year, the Wattenberg was the only significant contributor of oily revenues to its income statement.

In 2008, 80% of its production was gas; this year, the forecast is to exit 2011 with 35% oil and gas liquids. "On the revenue side, we'll probably see almost two thirds come from oil and gas liquids," McCullough says. "Top-line margins in our liquids projects are probably 4:1 over our natural gas projects today."

A traveling JV

Originally a Gulf Coast- and Gulf of Mexico-focused producer, PetroQuest Energy Inc. pushed far onshore in the early 2000s, picking up a position in East Texas, and then in Oklahoma's Woodford and Arkansas' Fayetteville shales. In the past year, it added Niobrara and Eagle Ford to its portfolio.

"The only areas where we don't have a significant amount of liquids potential are the Woodford and the Fayetteville," says Charlie Goodson, chairman, president and CEO of the Lafayette, Louisiana-based small cap.

The economics of those are fine too, he notes: It's in a joint venture in the Woodford with a public power company. "Because of this JV, our rates of return in the Woodford are somewhat insulated and are attractive even in a low-gas-price environment," Goodson says.

In the Fayetteville, most of its acreage is held by production and it's a nonoperator there, with BHP Billiton Ltd. and ExxonMobil Corp.'s XTO Energy business unit leading the program across its working interests. "We don't anticipate any issues as for holding all that acreage as well. They are continuing to drill, but it's less than 10% of our drilling budget."

In the company's roughly $100-million, 2011 budget, it plans to spend 63% on its liquids-rich prospects on the Gulf Coast and in the Gulf of Mexico (25%), East Texas (16%), Eagle Ford (12%) and Niobrara (10%). "Our production is approximately 20% oil and gas liquids right now. We anticipate that increasing at least 10% this year."

Among the company's forecasted drilling spend on gassy acreage, only 2% is slated for non-promoted, dry-gas projects; the rest will be drilled under a promoted cost structure. "And, in all of our portfolio, we have a very strong projected rate of return, even in a $4 dry-gas environment."

In a legacy holding, it is also horizontally targeting, like Goodrich, the Cotton Valley's liquids-rich Taylor sand—as well as the Davis sand—in Carthage Field in Panola County on the Texas/Louisiana border. Its wells there IP 20 to 30 barrels of oil and 50 to 75 barrels of gas liquids per 1 MMcf of gas. Its 47,000-acre block has geologic records of some 75 penetrations to date, and PetroQuest owns it 50/50 with Chevron Corp.

"We were starting a horizontal Cotton Valley program in the summer of 2008 when the financial collapse happened, so we pulled that program back and reinitiated it this year. We're on our third well as we sit here today."

Taylor sand is at about 10,000 feet. Laterals will be about 2,500 feet; frac stages will average 10 per well. Improving the economics is that the formation doesn't require a super-horsepower rig; the 1,000-HP type will do, he notes.

Charlie Goodson, chairman, president and CEO of PetroQuest Energy Inc., expects the company's production to rise by at least another 10% in 2011 from its current level of 20% oil and gas liquids.

Meanwhile, development of its Niobrara and Eagle Ford leasehold will progress under its JV that began in the Woodford, but was designed to be carried into other plays. "Clearly the Niobrara is almost all oil and some associated gas. In the Eagle Ford, we are expecting oil, gas liquids and a little dry gas."

It hasn't drilled a first hole into its Eagle Ford leasehold yet, but wells nearby are making 70% to 80% oil and an additional 5% to 10% gas liquids, he says. He expects the well cost to run some $7.5 million.

And, in pursuing its Gulf of Mexico liquids targets, a drilling permit is not a problem. PetroQuest already holds permission to make its four sidetracks at Ship Shoal, anticipating IPs of 500 to 1,000 barrels a day each. Its other Gulf and Gulf Coast projects are all onshore or in state waters.

Goodson is looking at acquisitions this year, as the company is in the best financial shape it has ever been. It reissued $150 million of high-yield bonds recently and has an undrawn $100-million credit facility and $60 million of cash on hand. "We are about as acquisitive as we have ever been," he says.

Back in 2002, all of the company's production and reserves were from the Gulf Coast or the Gulf of Mexico. "East Texas, the Woodford and the Fayetteville changed that." Today, 87% of its reserves and 54% of its production are from outside the Gulf Coast and Gulf of Mexico.

"Our production is already 20% liquids and we are active in two new plays, the Niobrara and the Eagle Ford. We don't have a large amount of acreage expiring. The JV will take us to grow in new areas. Where most JVs involve only one play, ours is more interactive."

Yet, don't discount gas. He emphasizes economics at all times in choosing capex targets, he says, and gas projects are not ruled out. "We are looking at a lot of projects. Liquids-rich is our primary target, but if a dry-gas project is so obviously economic, we are not going to shy away from it just because it's gas.

"Everybody is going to liquids right now, but there is some gas in the equation that still makes sense."

Comments