Questar Corporation Q3 2005 Earnings Conference Call Transcript (STR)

Third-Quarter 2005 Teleconference Script

Steve Parks

Good morning. Thank you for joining us for a review of Questar’s results for the third quarter and first nine months of 2005. I’m Steve Parks, senior vice president and chief financial officer. We had a pretty good quarter – net income was up 78% compared to a year ago. The increase was driven by higher production and realized prices for natural gas, oil and natural gas liquids, and increased volumes and margins in gas gathering and processing. Our earnings release – issued yesterday – provides a more-detailed review of our results and is available on our Web site at www.questar.com.

Following my remarks, Keith Rattie, our chairman and CEO will provide an update on operations and comment on our outlook for the rest of 2005 and our initial earnings and production guidance for 2006. After Keith’s comments we’ll take your questions. We have with us today other members of Questar’s senior management, including Chuck Stanley, president and CEO of Questar Market Resources; Allan Bradley, president and COO of Questar Pipeline, and Alan Allred, president and CEO of Questar Gas.

Our remarks this morning will contain forward-looking statements about the future operations and expectations of Questar Corporation. These statements are made in good faith, and we believe they are reasonable representations of the company’s expected performance at this time. Actual results may vary from our stated expectations and projections due to a variety of factors that are described in our Form 10-K and 10-Q filings with the Securities and Exchange Commission.

Now, let’s review our third-quarter financial results. For the third quarter of 2005,

Questar’s net income was $65.8 million, or $.75 per diluted share, compared to $36.9 million, or $.43 per share, in the 2004 period. There were 87.4 million diluted common shares outstanding in the current-year quarter compared to 85.9 million a year ago. Once again, our Market Resources subsidiary led the way for earnings growth – up 75% from a year ago. You’ll recall that Market Resources engages in gas and oil exploration, development and production, gas gathering and processing, wholesale gas and oil marketing and gas storage. Market Resources net income was $65.3 million in third- quarter 2005 compared with $37.2 million in third-quarter 2004.

Key drivers for Market Resources were higher production and realized prices for natural gas, oil and natural gas liquids, and increased investment in Wexpro. Also, gas-gathering and processing margins were higher, and NGL volumes rose significantly.

Market Resources subsidiary Questar E&P grew production 16% to 29.2 bcfe (billion cubic feet equivalent) compared to 25.3 bcfe for the 2004 period. Our Pinedale play in western Wyoming accounted for most of our growth. Pinedale production grew 72% to 8.7 bcfe compared to 5.1 bcfe a year ago. At the end of third-quarter 2005, Market Resources operated 127 producing wells at Pinedale – 39 more than a year ago. Market Resources realized a $.6 million after-tax gain in third-quarter 2005 from the sale of assets. Uinta Basin production – located in central Utah – grew 4% in the third quarter over a year ago. Rockies Legacy production – which excludes Pinedale and Uinta Basin – was flat with the prior year. Midcontinent production grew 1%.

Questar E&P’s average realized natural gas price increased 26% in third-quarter 2005 to $5.12 per Mcf (thousand cubic feet). The company hedged or pre-sold about 81% of gas production in the period at an average price of $4.89 per Mcf, net to the well. On an energy-equivalent basis, natural gas comprised about 88% of Questar E&P production in the third quarter of 2005.

Questar E&P’s pre-income-tax cost per unit of production rose 11% to $2.82 per Mcfe in third-quarter 2005 compared to a year ago. Higher production taxes accounted for 59% of the year-to-year increase, as a result of higher commodity prices. Depreciation, depletion and amortization expense rose 12% in the third quarter to $1.19 per Mcfe. The company’s drilling and completion costs were higher because of rising day rates for rigs and other services and steel prices.

Wexpro’s net income for the third quarter 2005 was $11.3 million, compared with $8.7 million for the year-earlier period. Wexpro’s investment base increased to $198 million, up $32.6 million over year ago. Wexpro also benefited from higher oil and NGL prices in 2005.

Market Resources’ Gas Management subsidiary increased net income 53% to $7.3 million in third-quarter 2005 compared to a year ago. Gas Management’s NGL volumes grew 62% over the year-earlier quarter due to the first-quarter acquisition of a gas- processing facility. Gathering volumes increased 17% to 63.8 million MMBtu (million Btu) for the current quarter compared to 2004 due to growing equity and third-party
Pinedale production and new gathering and processing projects in the Uinta Basin.

Questar Pipeline, our interstate pipeline and storage business, earned $9.2 million in third-quarter 2005, up 15% over 2004. The FERC (Federal Energy Regulatory Commission) approved a settlement in July that resolved a dispute over revenues from NGL (natural gas liquid) sales. The settlement required a refund of one half of a previously accrued $5.4 million liability. The other half of the accrual was reversed, adding $1.7 million after tax to earnings. Excluding the settlement, Questar Pipeline’s third-quarter earnings were $0.5 million lower than the 2004 period due to lower NGL sales revenues.

Questar Gas, our retail gas-distribution utility, reported a higher seasonal loss of $9.9 million in the third quarter of 2005 compared to a $9.8 million loss a year ago. Higher bad-debt expense and labor costs and a 4% decrease in usage per customer during the current-year quarter offset increased revenues from a 3.1% year-over-year increase in customers.

Now, I would like to give you a brief update on our capital-investment plans. Our board of directors recently approved an increase in our capital-investment program for 2005 to $690 million, up from $587 million, primarily for drilling and related gathering at Pinedale, with $525 million allocated to Market Resources and $83 million each to Questar Pipeline and Questar Gas. The board also approved our 2006 capital program of $712 million. This total breaks down with $490 million to Market Resources, $122 million to Questar Pipeline, $99 million to Questar Gas, and $1 million for Corporate and other operations.

Now, I’ll turn the microphone over to Keith Rattie, Questar chairman and CEO.

Keith Rattie

Good morning, everyone.

Steve has covered third-quarter and year-to-date results. I’m going to cover our outlook for the remainder of the year, provide an update on key operating activities, and comment on our initial earnings and production guidance for 2006.

Note that we now expect 2005 earnings to range from $3.50 to $3.60 per share. That’s up from our earlier guidance of $3.25 to $3.35 per share, primarily due to higher natural gas and oil prices, and better-than-forecast results from Wexpro and our gathering and processing business. Please note that our 2005 guidance now includes the two-cent-per-share contribution from the resolution of Questar Pipeline’s gas-liquids dispute with shippers. We’re also assuming a three-cent-per-share contribution from the pending resolution of

Questar Gas’s nearly seven-year-old gas-processing dispute with Utah state agencies. As always, when we give guidance we exclude one-time items and assume realized prices for unhedged production consistent with the current forward curve. Note that with hedging we’ve essentially taken commodity-price risk out of the equation for the rest of 2005. We’ve now hedged about 80% of our forecast production in the fourth quarter.
Also note from the attachment to our release that we’ve hedged additional gas and oil volumes for 2006, 2007 and 2008. We continue to hedge in a process analogous to dollar- cost averaging, when the market gives us an opportunity to lock in returns and protect our cash flow and earnings from a significant decline in commodity prices.

Turning to operations, Questar E&P grew production 16% in the third quarter to 29.2 bcfe compared to 25.3 bcfe in the year-ago quarter. We now expect that Questar E&P’s 2005 production will be in the middle of our 112 to 114 bcfe range. In the third quarter we got a boost in production when we completed and started production on the eight wells we drilled from our winter pad. We still expect to complete 35 wells at Pinedale this year despite challenges with rig and crew availability. We’ve hit our goals with our summer drilling program. We’ve averaged about 47 days from spud to TD at Pinedale this summer, compared to about 65 days per well a year ago. In fact, we’ve recently drilled several directional wells in less than 40 days – so we think we still have room for improvement.

We’re not aware of any other Operator at Pinedale that’s getting these results. Our Pinedale team has changed our basic well design. We’re drilling smaller wellbores that generally drill faster with smaller and less expensive bits, plus smaller-diameter and therefore lower-cost casing. We’ve also cut costs by drilling all pad wells to intermediate-casing point before switching to oil-based drilling fluids. Oil-based drilling fluids, combined with improved PDC drill bits, have also helped us cut drilling time significantly. What’s more, with limited winter access we can now control more rigs year-round between Questar E&P and Wexpro, so we’re hanging onto better rigs and more stable crews.

One of our third-quarter highlights was the August 9 Wyoming Oil and Gas Commission approval of 10-acre-density drilling for Lance Pool wells on about 12,700 acres of our Pinedale leasehold. With 10-acre density we now believe we’ll need to drill up to 932 wells to fully develop the Lance Pool on our core leasehold.

We get a lot of questions about our deep well at Pinedale, so in the spirit of being fully responsive to investors who want it, let me give you a fairly detailed update. Recall that in mid-August we TD’d the deep well in the Hilliard Shale at a depth of 19,520 feet. We logged the well and identified multiple zones of interest in both the Rock Springs Formation and the Hilliard Shale over a 3,500-foot interval from about 16,000 to 19,500 feet. Based on the logs and the gas shows we saw during drilling, we opted to run casing to total depth.
In mid-September we pumped three frac stages to test the Hilliard Shale over a 900-foot interval from about 18,500 feet to about 19,400 feet. Initially, the well came on fairly strong, at extrapolated flow rates as high as 10.7 million cubic feet per day of dry, sweet gas, and 2,400 barrels per day of frac water – and with up to 12,000 pounds flowing casing pressure through an 18/64 inch choke. We produced gas to sales for about 32 hours. Rates and pressures declined steadily but remained significant. During this flowback period, the production rate and flowing pressures fluctuated more than you would expect, for reasons we now think might be related to the inflow of formation material – shale and proppant – through the perforations and into the wellbore. In fact, the well choke plugged several times during flowback, forcing us to shut in to clean it out. Then, after about 32 hours the well plugged off completely, with pieces of formation rock smaller than a pencil eraser mixed with proppant and chunks of the flow-through frac plugs we used to isolate each frac stage.
We re-entered the wellbore with coiled tubing and tagged up on what appears to be the top of the obstruction at about 6,800 feet below the surface. We have no way of knowing how big the obstruction is – could be a few feet, or the entire wellbore could be filled with debris all the way to bottom. We’re seeing some communication with the open perforations because the well has built up pressure at the surface to over 13,500 psig since we shut it in.

So where do we go from here? Given these very high pressures, we’ll need a high-pressure snubbing unit and a very experienced crew to try to circulate out the rubble inside the wellbore and either re-establish production from the initial test interval or isolate it with a plug so we can move uphole to test additional zones. We looked but couldn’t secure the right snubbing unit and crew for this operation before cold winter weather makes this operation risky. Safety comes first, so unfortunately, we’ve had to shut down for the winter. We’ll resume testing next spring.

So what do these early results mean? Frankly, we don’t know. We expected to test gas in the
Hilliard, but the test was too short and the flow too unstable to draw any conclusions about long-term production rates or reserves. And since we know we have at least some shale in the wellbore, we’re concerned that at these depths and pressures the formation might turn to rubble at the differential pressures required to flow gas at economic rates. We’re in uncharted territory – to our knowledge, nobody’s ever tried to frac and produce from shale at these depths and pressures.

On the positive side, we now know that the Hilliard will flow gas at these depths. The Hilliard, by the way, is the stratigraphic equivalent of the Baxter Formation that we’re producing in the Vermillion Basin. I also remind you that the Hilliard wasn’t our primary target in this Pinedale deep test. Our primary target is the Rock Springs, above the Hilliard Shale, which we have yet to test, and unfortunately now won’t be able to test until next year.

That’s probably more detail than some of you wanted, but if not, please tag Chuck Stanley when we get to Q&A.

Let me turn to other activities at Pinedale. Questar Gas Management, our gas-gathering and processing-services business, is now in the process of starting up the $35 million condensate and produced-water gathering pipelines and related facilities, and will have them in service in time to satisfy the BLM conditions for expanded access this winter. With these facilities, we eliminate over 25,500 truckloads of produced liquids per year at peak production from just Questar’s operated acreage. We also eliminate the related air emissions, dust, noise, visual and traffic impacts.

Let me turn to the Vermillion Basin, our emerging new unconventional gas play in southwestern Wyoming and northwestern Colorado, and give you a drilling update. We now have extended production tests from two new wells, Alkali Gulch #1 and Canyon Creek #41. The Alkali Gulch well IP’d last spring at over 4 MMcfd and is currently making about 1.5 MMcfd. We estimate ultimate recovery could be 4 to 5 bcfe from this well. Canyon Creek #41 has been on production since September 21 and so far, based on initial production performance, looks a little better than Alkali Gulch – but it’s still too soon to tell. After a little over a month on production, C.C. #41 is making about 2 MMcfd.

In July we reached total depth at about 14,000 feet on a third new well, the Hiawatha Deep #5. You’ll recall that we reported last quarter that we dropped a string of coiled tubing in the wellbore. It took us several months to fish it out. We’ll frac this well shortly and it should be online by mid November. We’re now drilling our fourth new well in the Vermillion Basin, the Canyon Creek #47 well, and with luck we should reach TD by the end of the year. We also continue to get good production from two partially recompleted older wells, Canyon Creek #34 and Hiawatha

Deep #2. Recall that these old wells were drilled for other horizons, and the general well design was far from optimal to test the targeted Dakota, Frontier, and Baxter zones.

Please note: in 2006 we now plan to drill at least a dozen wells in the Vermillion Basin to further define the aerial extent of this play. Recall that Questar is by far the largest leaseholder and Operator in the Vermillion Basin with over 140,000 net acres, all of which are operated with an average working interest of over 90%. Most of our acreage is on BLM- managed public lands, subject to an existing Environmental Assessment. If the play continues to develop the way we hope it will, we’ll need a new Environmental Impact Statement and, in fact, we’ve already begun work on it.

In the interest of time, I’ll defer discussion of our Uinta Basin and Midcontinent activities to Q&A. But I would note the outstanding job our seasoned teams of asset managers have done replacing decline and growing production modestly from these mature areas. When we get to Q&A, you should ask Chuck for an update on our new Flat Rock and Wolf Flats wells in the Southern Uinta Basin, and for an update on the Midcontinent.

Let me turn briefly to our regulated businesses.

Questar Pipeline has commissioned part of the $55 million southern system expansion project. This project will add over 100 Mdth (thousand decatherms) per day capacity from the Uinta and Piceance basins to the Kern River Pipeline at Goshen, Utah. Our investment is underwritten by 10 and 20-year contracts with power-plant owners and producers. We estimate that it will add 3-4 cents per share to Questar earnings in 2006.

Turning briefly to our utility, in the third quarter Questar Gas reached a settlement with the
Committee of Consumer Services and the Division of Public Utilities, both Utah state agencies, hopefully ending the seven-year-old gas-processing dispute. For the first time since the dispute began, the parties now agree with the conclusion that Questar Gas reached back in 1997 – that the safety issue is real, and that gas processing is the most cost-effective way to protect customers from the risks related to changing heat content in the gas flowing into the Questar Gas distribution system. The proposed settlement requires Public Service Commission of Utah approval. If the PSCU approves the stipulation, Questar Gas will recover $3.6 million of costs previously expensed for the period from February 1, 2005, through September 30, 2005. Questar Gas would also be allowed to recover go-forward costs through January 2008. These costs have averaged about $5.7 million per year. The actual go- forward costs will vary because cost recovery includes plant fuel costs.

Let me shift now to our outlook for 2006 and beyond. Earlier this week the Questar Corporation board of directors reviewed and endorsed our five-year business plan.

We estimate that Questar 2006 earnings could range from $4.50 to $5.00 per diluted share.

The lower end of the estimate is based on an assumed average NYMEX price of $9 per Mcf for currently unhedged 2006 natural gas production, with Rockies basis ranging from about $1.30 to $1.60 per MMBtu. We assume an average prompt-month NYMEX oil price of $60 per barrel on unhedged oil volumes. The upper end of the range is based on an average

NYMEX gas price of $11.50 per Mcf and an average prompt-month NYMEX oil price of $63.00 per barrel for unhedged volumes. Note that with hedging we’ve taken significant commodity-price exposure out of the equation for 2006. With about 65% of our forecast 2006 production hedged, we estimate that a $1 change in the average NYMEX price of natural gas will result in an $18 million change in net income, or about 20 cents per share. Similarly, a $1 change in the average prompt-month NYMEX price of oil will result in a $0.4 million change in net income, or about one-half cent per share.

We estimate that Questar E&P 2006 gas and oil-equivalent production could range from 120 bcfe to 122 bcfe, unchanged from the guidance we gave earlier this year, as rig and crew availability continue to be issues. This estimate is based on 42 wells at Pinedale next year. We expect continued upward pressure on our cost structure, which we’ll continue to work hard to offset with productivity gains. We expect 5 to 10% earnings growth from Wexpro. Coming off of a year with record-high gas-processing margins, Gas Management earnings could be flat to down slightly versus 2005 depending on frac spreads, which are currently underwater for 2006. We expect Questar Pipeline earnings to grow by 2 to 4%. We expect the utility to earn at or near its 11.2% allowed return on equity in 2006, but there’s downside for our utility. Because about 70% of Questar Gas’s revenues are based on volumes, Questar Gas earnings are sensitive to customer usage. We estimate that a one-decatherm change in average annual temperature-adjusted usage per customer – that’s less than 1% of a typical customer’s annual consumption - will result in about a $1 million change in Questar Gas earnings.

In summary, Questar is on track for a strong finish to 2005, with a lot of momentum heading into 2006. Looking out beyond next year, our five-year plan shows that Pinedale will continue to drive Market Resources production and earnings growth. The key issue is: How many wells can we drill each year? We still have about 800 wells left to drill on 10-acre density at Pinedale. We may have a significant new play in the Vermillion Basin kicking in later this decade – we plan to drill at least 12 wells there next year to further evaluate play potential, so we’ll be in much better position a year from now to quantify the potential impact on Questar E&P reserves, production and earnings. Wexpro has identified over $600 million of new investment, so Wexpro may continue near double-digit growth the rest of this decade. We also expect Gas Management to grow at double-digit rates over the rest of the decade as Pinedale volumes grow and as we expand our Green River and Uinta Basin gathering and processing hubs. If the Vermillion Basin develops the way we hope it will, it will create opportunities for our gathering and processing business. Finally, we’re counting on Questar Pipeline to remove pipeline bottlenecks in our core basins and help make major new export pipelines happen.
With that, we’ll now take your questions.

Operator:

At this time, I would like to remind everyone if you would like to ask a question, please press * then the number 1 on your telephone keypad. We will pause for just a moment to compile the Q&A roster.

Your first question comes from Scott Soler with Morgan Stanley.

Scott Soler::

Good morning, Keith and Chuck, and very good results. I wanted to ask you a few questions specifically related to E&P. And the first one is – you know, Ultra Petroleum had commented on their conference call that they see 10% greater gas in place at Pinedale. Does that match up with anything you’ve been looking at? Could you maybe comment briefly on that?

Keith Rattie:

I’ll let Chuck field that one, Scott, thanks for the question.

Chuck Stanley:

Scott, go back to last quarter when we talked about our initial impressions or actually during the quarter when we talked about our impressions and testimony that we put forth before the Wyoming Oil and Gas Conservation Commission in conjunction with our request for 10-acre density on acreage. We actually talked about an evolution in our view of gas in place in the Lance pool. We now believe that the estimated gas in place is double basically over what we originally suspected when we were drilling on 40 acres. And even with the 10- acre-density drilling, we’re recovering with average wells out there less than half of the gas in place that we calculated.

What’s the big change? The big change is a lot of work that’s been done on the rock properties, including water saturations and effective porosity and permeability, which means that a lot more of this section is actually productive than we originally suspected from our initial work.

Scott Soler::

Okay. I don’t know how much you can comment on this, it’s a little bit of a sensitive topic. But regarding the Natural Gas Week note on mule deer that came out a few days ago, it seems like you guys have been proactive in terms of building the pipeline system underneath and doing the single-pad drilling, that you’re doing everything possible you can to be sensitive to migrations of mule deer and other animals in the area. Could you talk a little bit about whether that article might be a little bit backward-looking? Or, what’s going on with you working with the various commissions and environmental groups?

Chuck Stanley:

Sure. First of all I think that the actual study has been widely misquoted and the data contained in it has been selectively used by folks with different agendas to further their arguments. Basic conclusions from the study are not surprising. Number one, deer don’t stand on active drilling pads or on active producing pads. They avoid areas where there’s been disturbance. That’s a big surprise, I’m sure, to everyone listening.

Deer do avoid the areas of human activity. But, interestingly, once the activity ceases, the study has shown that the deer do come back closer to the facilities than a lot of people thought they would. The key points from the study: First of all, it’s a multiyear study. We funded it because we want to see how our mitigation measures that we’re still putting in place are working – for example, building this liquids line and gathering system that will go into service this winter and totally eliminate 25,500 truck visits a year to producing wells at peak production.

That’s going to make a significant difference in the amount of human activity and, we think, long term will be very beneficial for the wildlife. In addition, with pad drilling, we’re concentrating our activities in the southern end of our acreage and, therefore, the entire northern 90% of our leasehold is basically undisturbed through the winter. Again, this is a laboratory, a large laboratory and a study in progress, and a lot of people are front-running the conclusions after one year.

The other thing that I’ll quickly mention is that there’s a lot of discussion about mortality rates. Southwestern Wyoming – in fact most of the Intermountain West – has been in the midst of a five-year- plus drought cycle and, as a result, forage and overall habitat quality are affected and deer-mortality rates are up. So, to make conclusions about directly linking oil and gas activity to deer mortality is a bit of a stretch.

Scott Soler::

Yeah. No doubt. Just two other quick questions: one is, inflation and the industry. EnCana and a few other companies have gotten a lot of people alarmed, I guess, about their cost structure because the oil- service companies, and particularly services like fracing gels, different sands, rigs – there’s a call on everything because of the fact that we’re going through such a big cycle right now for natural gas. Could you talk a little bit about where the pinch points are and also, because of year-round drilling, is that a bit offset with Questar? Or could you maybe help color in that for the next few years and provide your outlook?

Chuck Stanley:

Well, obviously, Questar, like every other Operator, is feeling the pinch, as you described it, from increased costs. We’ve seen 70%, 80%, 90% increases since the beginning of 2004 on key services and supplies. Rig day rates are up 70% plus, steel costs are up 80%, fuel has more than doubled, cement, pumping services, everything is generally up. On the drilling side, it’s a good story. As Keith mentioned in his commentary, we’ve been able to successfully reduce the number of average days required to drill a well at Pinedale from 65 last year down to 47 this year. In no small part, that’s a result of a lot of hard work by the folks that are running our drilling program. It’s also our ability to find and retain through this year-round drilling activity the very best rigs and very best crews. We still have a significant learning curve to go up and more improvement to make on getting more wells drilled. The result’s been that we’ve been able to offset most of the inflation that I just mentioned to you. Our wells are still costing within a couple hundred thousand dollars of what they cost a year and a half or two years ago. The pumping services and frac stimulation have also experienced an increase. We’ve been able to reduce cycle time by going to 24-hour fracing. We’re hauling materials in bulk, we’re putting frac crews on pads and completing multiple wells continuously, without stopping.

And we’ve also recently started using what’s called “slick water