Lee K. Boothby: became president of Newfield Exploration Co. in February 2009 and was also named chief executive at the annual meeting in May. Previously the head of A&D for the Houston company, he takes the reins from outgoing CEO and co-founder David A. Trice at a good time as the company completes its 21st year.

Newfield is now in full development mode in the Woodford shale in Oklahoma, where it is the leading operator with nearly 300 horizontal wells; and in Monument Butte, a Utah oil field with more than 1,400 producing wells. Big Gulf of Mexico output is scheduled to come online from several deepwater developments from 2010 to 2013.

Newfield grew proved reserves 18% in 2008; the Woodford is about 30% of that. More growth is ahead, aided by a breakeven gas price that is falling as improvements to drilling and completions continue. But since 2005, Newfield has diversified beyond the Woodford, which some Street observers thought was the company’s only growth vehicle.

“Newfield’s transformation is behind it,” says Boothby:. “We have 75% of our reserves onshore North America. We have oil in the Rockies, gas in the Midcontinent, shallow-water oil in Asia, and deepwater developments in the Gulf. We are about execution these days, and living within cash flow.”

The company also has a “new ventures” strategic planning team. “Go to a new zip code? We’ve done that, and I’m confident we’ll find new opportunities again.”

In late 2008, Newfield began talking about its 500,000 net acres in the Bakken oil play in North Dakota. Its Granite Wash tight-gas play in the Texas Panhandle is beginning to attract attention, with some wells outperforming shale wells on 60-day results. Boothby:, a native of Maine, moved to Louisiana as a child and graduated from Louisiana State University. The Tiger tradition continues as his son will attend LSU this fall, planning to become a petroleum engineer, like his father.

In the early 1980s while with Tenneco, Boothby: worked on a study of Coal County, Oklahoma, where the Woodford is reviving activity now. “You go away and never think of it again. That area represented days gone by…and now here I am years later. It’s really neat. I tell young people, ‘I guarantee, there is something out there under your nose that, 15 years from now, you’ll say, how could we have missed this?’”

We visited with Boothby: at the Newfield offices to get a bead on how the company is faring and find out what he plans next.

Investor: Since 90% of your Woodford acreage has one well per section, or is HBP (held by production), how has your game plan changed?

Boothby: Most of the acreage we put together has a primary term of three years, so we had no choice but to drill it all, or have our friends compete with us. Early on, we were virtually the only company poking around out there so it was easier, but we did have to go from assessment to a “control-the ground” phase. We pushed to get one well down within the primary term for each section. Shortly after our original vertical well tested in June 2003, I came down to Houston (from Midcontinent headquarters in Tulsa) and pitched Trice to give me more dollars to go lease. All through ’04 and ’05 we built our lease position.

By mid-’07, we had 17 rigs drilling—that was our final push to get the acreage captured. Out of our 165,000 net acres, we are now HBP on 95%.

Investor: So you can “relax” now?

Boothby: We’ve gotten the lease clock to stop ticking, and we avoided the frenzy in ’07 and ’08 when you were reading about a new shale play every day. When the market cratered last year, it was a good feeling to know our core acreage was HBP. Now, we can control our development pace.

Investor: How are you bringing F&D costs down in the Woodford?

Boothby: About mid-2007, we started inching toward development mode and we tried four wells on 40-acre spacing. We did one frac stage every 800 feet, then decreased that to every 400 or 500 feet. In 2008, pad drilling became the norm. Our average lateral was about 4,500 feet with nine frac stages. This year we’re trying 5,000-foot laterals with 10 stages, and we plan two wells with 10,000-foot laterals. With smaller fluid volumes, pad drilling and longer laterals, we’ve taken costs from the $2.50 range down to $1.80 per Mcf.

But there are good models and bad models for breakeven costs. We loaded ours with all the costs: royalties, fuel, acreage. Please use all the numbers! Our conclusion for some time has been that there is not as much difference in these plays as some people like to believe. We can generate returns in a $4 environment. Do I prefer $7? Absolutely.

Investor: The new Arkoma Connector will improve your realized prices.

Boothby: We won’t be exposed to the big gas-price differentials we saw earlier this year. Our realized price will be about 70 or 75 cents less than a Gulf Coast price. The play now has about 850 horizontals and we’re working interest owners in about 60% of them. We have about 250 million a day of gross production—and another 25 wells waiting on completion.

The industry is producing 650 million a day out of the Woodford, versus zero in 2005. The price stimulus we had early in the decade and the technology tinkering is big for these unconventional plays. North America’s got 100-plus years of reserve life…I suspect there’s even more to learn. I’m excited.

Investor: What about the Granite Wash?

Boothby: Our first vertical well in 2003 was about 300 Mcf a day, but our first horizontal, in 2008, came in at a stabilized rate of almost 30 million a day—that’s 100 times the first well. The satisfaction from this is the pride our young people had as they articulated that to management. That was exciting.

Investor: Does Monument Butte generate that excitement?

Boothby: Absolutely. It’s our second-largest asset and we have more than 2,500 locations. Again, our hedge position now and going into 2010 gives us headroom to operate. Fortunately, $30 oil didn’t last too long. At $50 and $60 we generate a handsome before-tax return of 40%. The biggest thing there is matching our production to market demand. We’re at 16,000 barrels a day and we’ve got a deep inventory.

Investor: How much are you pursuing gas in Monument Butte?

Boothby: We’ve got a great position in Monument Butte, just to the west of Natural Buttes, which is a proven deep-gas play. We drilled half a dozen deep wells in 2008 to multiple targets: Mancos shale is the primary one, and there is Dakota, Mesa Verde and Blackhawk. It’s all HBP, so again, there’s the optionality of our portfolio. I think it’ll be another multi-Tcf supply.

Investor: Hedging, HBP and the right portfolio mix are your key strategies.

Boothby: We had a strong hedge position coming into 2009. We’ve consistently hedged to underpin our cash flow and returns from drilling. We didn’t enjoy seeing the market melt away beneath us last summer, but we didn’t feel stressed to do anything drastic. We have a good mix of projects between gas and oil, onshore and offshore, and between geographic areas. We have options.

We had to sit down and see how we’d play the back half of ’08 and what to look for in ’09. We shifted from gas projects to oil in the Rockies, and from high-pressure, high-temperature gas drilling in South Texas (which has been very good to us), to moving those rigs into the Midcontinent. We’ve really been able to see the benefit of our portfolio this way. With every day that goes by, we see every button to push and lever to pull. We are considering opportunities as they come available.

Investor: Do you mean drilling or A&D?

Boothby: I wouldn’t exclude anything from consideration, but in the near term, we believe our large onshore resource plays—the Woodford, Granite Wash and Monument Butte—are repeatable and scalable. Because we are virtually 100% HBP, we’ve got the ability to consider other zip codes. We’ve gone up the learning curve, but those learning curves weren’t free.

Investor: Any ideas yet about next year?

Boothby: Our capital budget for 2009 is about $1.45 billion. It allows us to deliver 6% to 10% production growth over 2008. We won’t take a position on the 2010 budget until year-end, but we expect activity levels comparable to this year, and we’ll benefit from service costs that are adjusting.

It’s hard to say we’ll drill this many wells in oil, this many in gas. In December when oil trickled down into the $30s, you would have said natural gas was advantaged. That’s when we dropped some oil rigs in the Williston Basin and Monument Butte. But by the second quarter of 2009, oil prices had recovered by 30%-40% and gas continued to deteriorate, so you see how things change. That’s where the hedge position, and having a game plan for reasonably consistent activity, pays off.

Investor: These commodity price swings make it difficult to plan.

Boothby: It does make it hard to plan. Probably the biggest change for Newfield is we are fortunate to have a breadth and depth of opportunities, and we can use that optionality.

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