It was inevitable. Denver-based QEP Resources Inc. rolled onto stock traders’ screens and into the S&P 500 Index on July 1, taking with it a full two-thirds of the market cap of integrated-gas parent Questar Corp.

The spin-off was the result of its success.

Ten years ago, Salt Lake City-based Questar aimed to grow its unregulated E&P business—and substantially. At the time, the E&P unit held some 730 billion cubic feet (Bcf) of proved Rockies reserves, mostly natural gas, in the San Juan, Western Canadian, Green River and other basins. By year-end 2009, the unit’s portfolio had quadrupled to 2.7 trillion cubic feet equivalent (Tcfe) of proved, all in resource plays, in the Rockies (1.65 Tcfe) and Midcontinent (1.1 Tcfe), making a half-billion cubic feet of gas equivalent per day.

Its leasehold is estimated to have total resources of some 30 Tcfe. Annual production growth in the past five years has averaged some 14%; average annual proved-reserve growth, 17%.

And, while investors were pleased, some were confused. E&P pure-play stock buyers didn’t or wouldn’t understand Questar’s business; lower-risk, such as utility-only, stock buyers were losing focus.

“We had recognized for some time that we had grown the upstream to the point where we needed to separate into two, pure investments, based on conversations with investors: one, the regulated; the other, the unregulated,” says Chuck Stanley, president and chief executive of the newly public E&P (NYSE: QEP).

Spinning off a gas-weighted producer at a time of underwhelming natural gas prices was no planning oversight. Instead, the timing had more to do with access to debt markets than with concerns about gas prices or access to public-equity markets, Stanley says. “We weren’t issuing new equity at QEP.” The spin-off was a one-for-one distribution of QEP shares to holders of Questar shares as of June 18.

“We didn’t need to be concerned with timing in the equity markets like we would have if it had been an IPO.”

An open debt market was essential because QEP would face the possibility of refinancing all of its roughly $1.2 billion of long-term debt when leaving Questar and its utility-type, investment-grade debt rating. As a higher-risk, E&P-only company, QEP’s debt would be rated one notch below investment grade, as is commonly assigned to oil and gas producers. A credit-rating downgrade, accompanied by a change-of-control trigger, would allow bondholders to present the paper for payment before maturity.

In early August, some $618 million of bonds were put to QEP. With debt markets still open, it issued $625 million of new bonds to fund retirement of those that were redeemed.

To date, shares of QEP and Questar combined are pricing at about $47 ($30 for a QEP share; $17 for a Questar share) or roughly the same price as Questar shares pre-spin-off, with QEP shares dragged sideways by low gas prices, instead of the E&P stock rocketing from being unleashed as a pure play from the conglomerate.

“There just isn’t a lot of conviction in buying and selling E&P stocks right now,” Stanley says. “The volume (of E&P stock trading) is down across the board. The natural gas market is certainly not bolstering investor enthusiasm.”

The stock price is also being restrained by some mandated in- and out-trading. The shareholder base of QEP is changing from being initially identical to Questar’s.

“There is a whole set of shareholders—those that have mandates to invest in E&P names—that need to migrate into our stock and there is a whole set of shareholders—those with fund objectives focused on lower-risk utility investments—who need to migrate out.”

Stanley expects a profound shift. “The top 25 holders of our E&P peer companies were conspicuously absent from Questar’s shareholder list on June 30. We’re seeing a heightened interest from those funds now.”

QEP’s listing in the S&P 500 Index will also affect the shareholder base. Questar had been in the 500 and was pushed to the S&P 400 upon spinning out QEP. The listing brings more interest in QEP stock, yet it may have created additional selling pressure as fund managers rebalanced their index funds to reflect the substitution of QEP for Questar in the 500, Stanley says.

Hedging, Liquids

No longer part of a utility, QEP expects to change up its hedging strategy. While some 75% of its 2010 production is hedged, Stanley aims to hedge 50% in future years, exposing the company and its investors to greater commodity-price volatility while continuing to backstop a portion of its downside exposure.

Some 50% of 2011 production is hedged at an average net-to-the-well price of $4.91 per thousand cubic feet (Mcf); factoring in the Btu content, gathering costs and basis differentials, Stanley says the hedge price is equivalent to a Nymex price of close to $6.

The company’s production profile is also changing. It currently is 89% gas and 11% gas liquids and oil, with a revenue split of 80% gas and 20% liquids, but it will become more weighted to liquids in time, he says.

“This year, roughly 35% of QEP’s revenues will come from oil and liquids sales and fee-based gathering and processing revenues from our field-services division, but with drilling focused on liquids-rich plays and a new processing plant coming online in late 2011, dry-gas revenues could decline to about 50% of total revenues during the next several years.”

To capitalize on its liquids-producing acreage, it has reassigned one of the six rigs it has had working its massive Pinedale Anticline gas-manufacturing play in Wyoming to drill a Niobrara oil-shale test of its acreage in the Denver-Julesburg Basin in southeastern Wyoming. Once the test is drilled, that rig will join one that is drilling QEP’s Bakken oil leasehold in North Dakota.

Already, QEP had been shifting away from Rockies-only gas production. While more than 75% of its production was from the Rockies a decade ago, more than 50% is from outside the region now.

It acquired a leasehold in the sweet spot of the Haynesville shale in northwestern Louisiana several years ago while operators were still primarily targeting the Cotton Valley and Bossier gas sands there. That expanded its gas footprint to the Midcontinent.

Meanwhile, it grew its exposure to wet gas and crude oil by adding holdings in the Granite Wash play in the Texas Panhandle and in the Woodford/Cana shale in Oklahoma. In the Rockies, it began to add momentum to its oily Uinta Basin holding in Utah, where it makes some 3,000 barrels of waxy crude per day.

“In addition, we started looking outside the gas-prone Rockies basins that had been our traditional focus, and the Williston Basin came to our attention.”

QEP owned mineral rights in the basin that hosts the Bakken/Three Forks oil play and it participated with EOG Resources Inc. in some of its early wells at Parshall Field. “We saw astounding results from those wells.” Quickly, it bought more leases and now holds some 89,000 net acres near Lake Sakakawea.

Capital Allocation

Capex planning for 2011 is under way, and Stanley expects greater allocation to liquids-rich plays, except where rigs are needed to work to hold gas acreage, such as in the Haynes­ville, and where the company’s scale has assured cost economy, such as in the Pinedale.

In the Haynesville, he estimates two rigs are needed to hold QEP’s 49,000 net acres by production before the leases expire. In the play for just a few years, the company has booked 592 Bcf of proved reserves and estimates some 1,300 additional well locations at 80-acre spacing on its leasehold. Seven rigs are at work for QEP there currently, “so there is opportunity to slow down a bit there.”

In the liquids-rich Granite Wash, where it holds 26,500 net acres and has two rigs at work, and in the Woodford/Cana, some acreage will begin to expire in 2012, so those plays will also continue to capture capital, Stanley says.

In the Granite Wash, the company has been drilling to the lowest wash member, the Atoka, to test its liquids content as well as to hold its acreage to the lowest depth of the wash horizon. The Atoka wells are making a surprising amount of liquids, Stanley says, “an indication that the petroleum system—particularly the vertical and lateral position of dry gas versus liquids-rich gas—is a lot more complex than we originally anticipated.”

In the Woodford/Cana shale, it holds 66,000 net acres and has two rigs at work, and gas liquids are between 25 and 80 barrels per million cubic feet of dry gas. The company estimates it has 2,700 more drilling locations on its acreage at 80-acre spacing.

From the Bakken, recent initial-production rates have exceeded 3,000 barrels per day, and estimated ultimate recovery (EUR) per well is currently 350,000 to 750,000 barrels equivalent, using 5,000- to 10,000-foot laterals and 22 fracture-stimulation stages to date. Other operators are now exceeding 10,000 feet and 40 frac stages.

As for the Niobrara, “it’s too early for me to speculate on what we’ll do,” Stanley says. “We’ll have to wait and see how our initial test wells turn out.” QEP holds 130,000 acres in eastern Rockies, liquids-rich basins in the Powder River (49,800 net), Greater Green River (17,400 net) and Denver-Julesburg (77,000 net).

Stanley says Bakken well-completion technology and results can’t be presumed to work in the Niobrara—the Bakken is not an oil shale, and the Niobrara is. “It is a misnomer,” he notes. Bakken production is from a carbonate and clastic or sand interval that is between two shales. “So, the Niobrara is a bit unique. There’s just not a lot of experience and expertise anywhere in how to complete these wells.”

Stanley is expecting to draw upon 1980s results from horizontal Niobrara wells in Silo Field in Wyoming that were drilled by Union Pacific Resources. The wells were successful but not fraced. “The average recovery per well in that field was roughly 100,000 barrels. One wonders what those wells would have recovered had they been completed with the current technology.”

The gassy Pinedale leasehold is the elephant in the company’s portfolio. QEP has more than 17,872 net acres there, all held by production, and 1.3 Tcfe of proved reserves making some 200 million net cubic feet equivalent per day. Upside is impressive with up to 1,400 remaining locations to drill if on five-acre spacing.

The economy of its scale in Pinedale and other plays will be weighed into capital-allocation plans, he says. While most producers have seen U.S. onshore oilfield-service costs double during the past few years, QEP’s completed well costs have declined at Pinedale. Average drill days there have fallen from 64 in 2004 to 17 this year and as few as 12 for one recent well. So far in 2010, gross completed well costs at Pinedale have averaged $3.65 million, compared with more than $6 million in 2003.

In the Haynesville, drill time has declined from as many as 90 days a few years ago to an average of 38 this year and as few as 24 for one recent well. QEP’s gross completed well cost in the play has averaged $8.7 million in 2010.

QEP’s finding and development (F&D) costs in the Haynesville are some $1.95 per Mcf equivalent. In the Pinedale, they are $1.29; Granite Wash, $2.04; and Woodford/Cana, $1.71. In the Bakken, $16.95 per barrel equivalent.

“We’ve been able to make some hard-won cost gains. If we completely shut down activity in some core plays, we will lose those efficiencies and, therefore, our low-cost advantage, and it would be very difficult to get it back. A lot of this is not the iron; it’s the human achievement that has differentiated QEP as a low-cost operator.”

The company’s second-quarter 2010 production cash cost (lease-operating expenses, plus production taxes, G&A and interest) was $1.58 per Mcfe produced, the fourth lowest among 42 other producers, according to a QEP and Credit Suisse analysis. The peer group’s cash cost averaged $3.30 per Mcfe, Stanley adds.

Acquisition Capex

Will QEP buy into more U.S. plays or into more of its existing plays? Stanley says the company has enough to drill. “We have about 30 Tcf of total resource potential. We have a portfolio of incredible, high-quality, unbooked potential that will propel organic growth during the next five to 10 years, without making a major acquisition.”

The “warehousing cost” of its existing holdings is very low, he says. Acquisitions are always possible, but QEP’s challenge is in finding assets better than its own; meanwhile, divestments are always possible too. “We will also constantly evaluate our portfolio and make economic decisions of whether to hold something or sell it, based on whether the net present value is greater in someone else’s hands than in our own.”

It is unlikely that the company will diversify into conventional plays or offshore operations, however. Any adds would likely be in resource plays, Stanley says. “Resource plays—tight gas, shales, horizontal wells, multi-stage fractures—that’s our core competency. We are extremely good in resource plays, so you can expect to see us continue that in the future.”

He also expects the company will continue to focus on maintaining a conservative balance sheet, operating mostly within cash flow. At the time of the spin-off, the company’s debt-to-EBITDA was 1:1 based on 2009 earnings of some $1.2 billion. Currently, it has $1.14 billion of long-term bonds outstanding at a weighted average cost of 6.76%. The $625 million of bonds that were sold in August to redeem those that had been put to it were at a 6.785% coupon discounted to yield 7% and are due in 2021.

Half of QEP’s outstanding bonds now mature in 10 years; before August, all were scheduled to mature by 2020. It also has a $1-billion revolving credit facility of which some $200 million is currently drawn, leaving dry powder of some $800 million. Total debt is $1.34 billion; the company’s market cap, $5.3 billion.

What will QEP look like at year-end 2011? “I believe we will have seen a migration in our shareholder base to one that is similar to that of our peers.”

In terms of portfolio? Continued diversification away from the Rockies; accelerated production from oil and gas-liquids plays; new gas-processing plants, bringing its field-services division’s net liquids production to 22,500 barrels a day from 6,000 today; and possibly a big win from its Niobrara tests.

Questar itself no longer holds an interest in QEP. Except for a shared chairman—well-recognized gas-industry veteran Keith Rattie—and providing some transitional services to each other for a defined period, “we’re no longer affiliated.”

His message to Wall Street? “We’re a new public company but, in our history, we’ve been able to put up mid-teens production and reserves growth in each of the past four years, and we have a track record of being a low-cost producer with the ability to continue that growth trajectory in the future while living within cash flow.

“We keep differentiating ourselves and making money, and the market will recognize the value of the company.”

Sidebar: The Midstream Mint

Some stock buyers are initially confused by the continued appearance of a conglomerate in QEP Resources Inc. that was rolled out as a pure-play E&P company in July. The company took with it from former parent Questar Corp. the gas-gathering and -processing unit, QEP Field Services, that supports its E&P operations.

Unlike other E&P companies that have gathering and processing assets as well, QEP separately reports its midstream results in its SEC filings, and will continue to, says Chuck Stanley, QEP president and chief executive.

And, he probably won't discontinue discussing the unit in quarterly-results announcements and investor conference calls: The midstream unit makes a lot of money. Of QEP's trailing-12-month EBITDA of $1.16 billion, 14% was contributed by the midstream business. Through June, the revenue contribution from total liquids production and fee-based gathering and processing was 34%, versus 66% from the sale of dry gas.

"Including field-services NGL (natural gas liquids) volumes, QEP's total production was 16% liquids through the first six months of 2010. It's not inconsequential. It's not a relatively minor part of our overall story."

Like other E&Ps that build their own take-away infrastructure, it does so only where it is active in exploration and production. "You won't see us out building midstream assets in the Marcellus if we're not an active producer in the play."

Building and operating the infrastructure assures QEP that its production taps into premium markets, he adds: Its output from the Pinedale play in Wyoming has access to every interstate pipeline that ships out of the region, for example.

"It allows us to add value that is not available to a producer who does not control the infrastructure. The E&P business benefits from the field-services business. We can develop and pre-build infrastructure to make sure our production flows to sales in a timely manner and that there is no capacity restraint."

QEP is currently expanding the field-services unit, building a processing plant in Wyoming that will take 15,000 barrels of its and other producers' NGLs out of the Pinedale play. This will contribute some $50 million of additional EBITDA to QEP's annual results in 2012. In Utah, a new plant will process 150 million cubic feet of gas per day.

"We'll see our NGL production in our midstream business today grow from a little over 6,000 barrels a day this year to 22,500 in 2012 as the second plant comes on.

"We break it out in our conference calls because we think it is an important part of our business."