Coterra Energy Inc (CTRA) 2004 Q2 法說會逐字稿

Good morning, my name is Jody, and I will be your conference facilitator today. At this time I would like to welcome everyone to the Cabot Oil & Gas Corporation's second quarter earning's call. All lines have been placed on mute to prevent a any background noise. After the speaker's remarks, there will be a question-and-answer period. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you.

Mr. Dinges, you may begin your conference.

Thank you, Jody. Good morning, thank you for joining us during the second quarter earnings teleconference call. As usual with me today are several members of our management team -- Mike Whalen, Senior VP; Scott Schroeder CFO; Jeff Hutton, VP of Marketing; Chuck Smyth, VP, Controller. As you're aware, I need to read this statement prior to our remarks -- The statements regarding future financial performance and results and the other statements which are not historical facts made during this teleconference are forward-looking statements that involve risks and uncertainties including but not limited to market factors, market price of natural gas and oil, results of future drilling and marketing activity, future production and costs, and other factors detailed in the company's Security and Exchange Commision filings. Securities and Exchange Commission files. All non-GAAP financial matters discussed during this conference call have been posted to our website at www.cabotog.com along with reconciliations tho the most directly comparable GAAP financial measures.

As last night's press release highlighted, Cabot posted net income of $19.3 million, or 59 cents per share, surpassing the second quarter net income record we set last year. Additionally, the company had discretionary cash flow of $60.2 million, nearly equal to last year's record figure. Contributing to these results were higher commodity price and lower overall expenses between comparable second quarters. As we all are aware, commodity pricing remained strong throughout the second quarter in spite of current storage levels. For the second quarter Cabot experienced a 12% increased in a realized natural gas price and a 6% increase in the realized oil prices. The impact of hedges had on our second quarter price realization was reduction of 75 cents per MCF for expired natural gas hedges, and for crude oil the impact was a reduction of $6.67 per barrel. Additionally, as a new table in the press release highlights, our future hedge positions that require mark to marketing accounting treatmentment increased quarterly gas revenue by $1,300,000, but reduced quarterly oil revenue by $2 million.

Subsequent to the second quarter in early July, Cabot management elected to add slightly to our 2005 hedge position with a wide collar on gas for 10,000 MMBTU per day, and a range swap on oil covering 1,000 barrels per day. The natural gas collar covers some of our east region production with a $5.25 per MMBTU floor, and an $8.75 per MMBTU ceiling. The range swap on oil was $5.75 above the straight swap indications at the time we made the trade, and provides for a price of $42.50 per barrel for all of 2005. With these two additions, Cabot is now approximately 35% hedged for 2005, and that assumes production levels in 2005 consistent with guidance levels for 2004. Just a note on that, during the third quarter, we will be working on our 2005 plan. We'll be in a better position to discuss anticipated production levels at a third quarter teleconference. Our expenses for the quarter improved between comparable periods. We saw lower operations, lower expiration, lower interest expense, along with lower brokered natural gas costs. Note worthy is the decline in exploration expense where the company had only one dry hole in its six-well second quarter exploration program. Also while brokered natural gas costs and corresponding revenue were down in absolute terms, the company saw an improvement in the quarterly margin over last year's comparable quarter.

As was pointed out in the quarterly press release, our G&A expenses increased in total due to two categories -- stock competition and Sarbanes-Oxley related covers. In the stock compensation category, Cabot continues to amortize any restricted stock that is awarded by the compensation committee based on price on the day of the award. The new portion of our stock compensation is the performance shares that the company put in place this year in lieu of stock options as a long term inventive. The advantage of performance shares is, one, it requires fewer shares to be awarded, and therefore less (INAUDIBLE) to existing shareholders, and, two, is based on relative comparison of total shareholder return for 16 peers. The company awarded 168,000 performance shares in February, with payout ranges from 200% to zero. With the move in our stock since April, and a requirement to mark to market these estimates, the company is currently in the top slot, the total shareholder return versus our 16 peers, therefore providing for a 200% payout. The $1.7 million expense represents 200% payout for the measured 4.5 month period since the award. In terms of Sarbanes-Oxley, after we see costs, and most public companies continue to creep up due to compliance efforts in accounting world that still has great deal of uncertainty on new rule requirements. This is basically an expense, non-value added exercise with significant ongoing costs. We expect our total bill for four '04 alone to be over $1 million by year end. Our new guidance for G&A assumes increases in Sarbanes-Oxley and footnotes the private payout level for expense to stock compensation.

Moving from the accounting world, as we have mentioned before, meeting our production guidance is a driver for Cabot, and we have accomplished this goal. The key reason delivering positive results was again the east region, which showed growth from both the year-over-year and the quarter-over-quarter comparisons. Also contributing was Gulf Coast with it's growing natural gas base. The Gulf Coast improvement was a result of continued success at at a Raymondville field in south Texas along with our exploration success in south Louisiana with Little Horn Bayou. The Little Horn Bayou discoveries that came on-line in June, just last month, are currently producing over 25 million cubic feet equivalent per day net from the two wells. As you may recall, Cabot has a 75% working interest in these two wells. This production has taken the Gulf Coast to 132 million cubic foot equivalent per day from the 113 million cubic foot equivalent we averaged for the entire second quarter. Pretty good boost. Regarding our oil production, the liquids-rich Gulf Coast CL&F properties continue their anticipated decline, which as we've previously mentioned before, this is the primary reason for the slight decline in our total oil volumes. The west production profile was slightly bow low guidance primarily due to a prior year -- prior period ajustment from an outside operated property. However, in the west, this is the time of year the drilling window opens. We have scheduled a ramp up in our activity level, assuming we go are not hindered any further by delays associated with our issuance of federal drilling permits. We have all of our paperwork in. We're awaiting 26 federal permits to drill various rocky mountain projects, anticipating the majority of those any day.

Also, regarding near term production, we have anticipated volumes yet to be turned in line from several of our announced successful wells. These include two wells in Breton Sound 41, Eugene Island 280, and Eugene Island 277 #A-3 well. The timing for this production to be turned in line is between August and November this year. The anticipated additional production to Cabot as approximately 15 to 20 million cubic foot equivalent per day net. With our completions and facility installation on schedule, we have a high degree of confidence that we will meet our production guidance for the third and fourth quarters, which remain unchanged.

In regard no our balance sheet, cash in the bank at June 30th was $21 million, down from the 52 million on March 31st. Some of the cash went for stock repurchases, while the vast majority went for reinvestment in the company based on original timing of our capital program. We do anticipate generating excess cash flow this year, as we have done the previous two years. This excess will be used to repurchase shares, fund additional slight increases in our capital program, approximately $11 million at this stage, and/or small acquisition opportunities which may arise. The latest increase in our capital program was to cover the addition of one new wildcat in Canada, one new well in the Gulf Coast, plus increases for facilities and pipeline directly attributable to our drilling success. We have also seen fairly significant costs increases for our tubular goods and drilling rigs. In terms of share repurchase, it will remain our goal and at a minimum, we plan to repurchase as many shares as are being exercised or awarded to grant, so now dilution occurs to our shareholders. Year to date, the new shares totalled approximately 500,000 shares.

Moving to operations. Our 2004 capital program remains on-track with an overall success rate of 98% year-to-date, including 100% success rate in the east on 81 wells, 11 for 12 in our company-wide exploration program, which puts together a pretty good first half. In the west region, Corral Creek, (INAUDIBLE), and the Big Horn Basin reached total depths, and casing has been run; testing will commence very shortly. Presently, our Gulf Coast program has allocated its capital right on schedule, our west program is now kicking off with 14 wells to be spud in the next two months, and the east region has 80 more wells to drill in the third quarter. This makes more for a very busy third quarter. With this level of activity, I'm hopeful we're as successful in the third quarter as we've been year-to-date. Presently drilling or scheduled to be drilled in the third quarter are several impact wells. The Gold Nugget in Wind River Basin, that's currently drilling. We have the 50% interest. Saunders in Canada, which is our (INAUDIBLE) prospect, is currently drilling. Soldier prospect in Canada is scheduled to spud this next month. We're getting a rig as we speak. Bull horn, which is in Paradox is scheduled for spud in September. Single Eagle, which is in the paradox also is scheduled also to spud in September. Just these five wells are going to expose Cabot to a net unrisked potential that will range from 75 to 150 BCF. Just a note on Soldier, like Gold Nugget, was mentioned in a first quarter conference call. We did switch the drilling order of Soldier and [Stolberg], which was mentioned as [Stolberg] is presently drilling.

I'm very pleased how our program has come together. What I really like about our program is Cabot's ability to expose the share holder to some impact upside as I just mentioned, but also provide a predictable program that organically grows our reserve base each year. To highlight this, our expanded program in the east region, which I've talked about a little bit, will grow its production, replace over 300% of its production at an excellent cost to find number, generate over $20 million of free cash, not to mention we have almost 4,000 undrilled locations on our existing acreage that has historically provided a 97% success rate. I think all companies would would love to have this program. Our west region is positioned well to take advantage of its recent exploration successes and embark, as a result of this success, on an expanded development program, which I feel will yield impactful results. Our Canadian operation has achieved a milestone for Cabot. We have now drilled and completed our initial exploration well as a new field discovery, and also just committed -- completed that well and commenced first production in Canada from this well Tuesday of this week at approximately 3 million a day.

I'm also pleased with a year-to-date drill bit success, particularly the positive results from a Gulf Coast Little Horn Bayou discoveries. As I mentioned, those discoveries have added significantly to our production profile. Combined, you have a program that is predictable yet provides near term production potential, and not only production, but also reserve growth. And with our financial flexibility, I think Cabot offers a tremendous opportunity in our future program.

With that, Jody, I'll be happy to answer any questions the audience might have.

At this time, I would like to remind everyone in order to ask a question, please press star then the number one on your on your telephone keypad. Your first question comes from Brian Singer from Goldman Sachs.

A couple of questions. First, the production Appalacia looks pretty strong, so a nice increase from the first quarter, and it was above your guidance. Did wells come in better than expected. Were there more wells drilled than expected? Could you just add a little there?

Brian, the east program, as you're aware, is the largest program we put together up there, and we -- we have so far been able to remain on track. We have seven rigs currently running up there, 80 wells in this current -- or this third quarter. Our current quarter is a pretty aggressive pace. But what we've seen in the first half of 2004 is a little bit better performance overall in the program than we anticipated. Also, I might just mention to you, also on the pipeline upgrades we have been able to put in place, and we've seen some increases from our base line production, with the infrastructure investment that we've made up there.

Great. And Little Horn Bayou also, if 25 million cubic feet a day is the net production, that seems like gross production is also better than your initial thoughts of 20 to 30. What is the sustainability of production at this level?

So far -- well, Gulf Coast production just comes at you very quick, Brian, and right now the wells are holding fairly flat. We have not seen any bobbles at this stage. We -- you know, in our guidance right now, I guess it's safe to say that with wells like that that do deliver such a high volume in percentage of our production, we're cautiously optimistic, and in our guidance we're cautiously optimistic that the wells are going to maintain at this level. But we do also anticipate that type of production, those types of reservoirs to start a predictable decline.

Great. And in terms of Etouffe, do you have a rate there for the quarter?

Let me see if I can get Mike. I don't know what it is.

Gross production for the quarter? I can tell you a daily rate, approximately about 38 million a day GAAP, Brian, and about 8,000 barrels of oil per day gross, and of course our net 24%.

Great. In the Rockies were there any new acquisitions of acreage at all? And do you have any plans to do that?

We did, around our Corral Creek prospect up there, we did acquire a fairly significant acreage position covering that area.

And what is -- what what is your total net acreage position now in the rockies? Is it now above 400,000 developed acres?

Yes, it is.

Great. Thank you.

Okay. Thanks, Bryan.

Your next question comes from Ray Deegan from Harris Nesbitt.

Yeah, hey, is Scott on the call, Schroeder?

He's right here.

He's right there? Great.

Hi, Ray.

How are you doing Ray?

Good.

I was wondering, on the deferred taxes, do you think that this is a, you know, a good rate to use going forward? It seemed a lot lower than what you saw in the the first quarter?

What do we have for that? What are we assuming in our plan? Ray, we're still using 50% deferral, 50% tax.

Okay. Got it. Going forward?

Yeah.

Okay. That's great. I guess just a question for Dan, what do you think about the Gulf Coast at this point? You know, it accounts for 51% of your production. Obviously, if you know -- have you found enough this year to give you some visability that you can maintain these kind of slow decline rates, or is the outlook starting to look like you may be up next year, or what do you think at this point?

I've been pleased with what we see in our drilling program in not only companywide, but the Gulf Coast, Ray. We -- I'm confident at this stage that we'll replace our production in the -- in the Gulf Coast.

Okay.

And we also do have these handful of offshore projects that are imminent to come on-line, and we have several projects, even though I didn't mention them, in the third quarter impactful wells here, we do have some Gulf Coast projects between now and year end that we're going to be drilling that I think will sustain our -- what we're seeing so far.

Right. Okay. And if you -- and then if you look and next year, do you think you'll still have some inventory remaining in Raymondville and in some of these other areas where you've had success? Or will you need to kind of reload and make an acquisition next year?

Well, no, we -- Ray, we just completed our board meeting Wednesday and Thursday, and our July board meeting sets up our exploration review where all of the managers from each region come in, and I was extremely pleased with every region of not only what they've done, but looking ahead and what we have in-house as already identified prospects, which are, I think Mike's count was 67 drillable prospects in our inventory as we speak. But also additional leads on top of that that we're continuing to develop and some conceptual plays that we're fairly far down the track on identifying what we think are going to yield some very interesting prospects down the road. So we're going to be able to, with a with what we have in house and known right now, we're going to be be able to put together a 2005 program that will certainly match the capacity of our 2004 program without a program.

That's great. Okay. And in Appalacia, I know you were drill some significant stepouts to try to, you know, prove up some of this three CTFs for potential reserves there you have there. What kind of results have you seen so far?

Well, we have had a very good rate of success, Ray. We are batting 100% in the east. Every well we have drilled has been successful.

Right.

And the data that we gather continues to build our program, and we have not seeing anything that we have done up there that is going to deter from our of optimism.

Okay. That sounds great. Thanks a lot.

Thank you.

Your next question comes from Ken Beer from Johnson Rice.

Good morning, guys.

Good morning.

A question just, Dan, you mentioned in the western region that there was -- that the volumes were a little lower than expected because there was an adjustment. Can you give us a sense at to what kind of -- or what what size adjustment it was?

It was about 300 million.

os really it would have been pretty flat with the first quarter?

It would have been pretty flat, yeah.

Okay. So if we look ahead the third quarter, in the absolute, without a -- I mean, if you make the adjustment back, you're basically flat in the second quarter. The third because of the step up in drilling, and fourth quarter should see a ramp, also, in the west?

Yes, correct.

Okay. That's great. And it's not lack of prospect as much as just permitting and timing as to when you can drill?

We are fairly frustrated with the -- how expeditiously the DLM is delivering these permits. We have had everything in place for a -- for an extended period of time. We have made repetitious calls to the regional offices. It has -- it has really hindered our capacity to get our commitments to our rigs, get our service side of our business lined up and start moving in a -- in an orderly fashion to get out there. We should, and we anticipate it, and the DLM in fact had indicated to us that we would have all of the permits for example in Wind Dancer by July 15th. We are still waiting for the final permits to be able to move a rig in in Wind Dancer. And we had nine wells that we were planning on drilling between now and when they close the window again in December in that -- in that particular area. So it's been frustrating, and I can't put my hands on the -- the limited access that they're providing us right now, but it is frustrating.

And they probably won't let you ES tend beyond December just because they were a little late in July. Funny how that works.

No, they'll close you out on the front end, but they're going to be watching you walk out the door on the back end.

Okay. Well, fair enough. Thanks, guys. I appreciate it.

Thanks, Ken.

Your nest question comes from Ellen Hannan from Bear Stearns.

Thank you. I just wondered of the 4,000 undrilled locations you have on the existing acreage, could you give us a breakdown, even if it's broad, in terms of region, and how much of that is covering kind of your three TCF of potential in Appalacia?

Yeah, we have all of the reference to the undrilled locations, Ellen, is solely in the east.

Okay.

And our -- our acreage position is a -- a very concentrated position in south -- in south and southwest West Virginia. We have in that number about 390 of the locations are (INAUDIBLE), and the rest or possible probable. The thing about that number is, and what I like about it, is, for example, we have 2350 wells that are current he producing up there, and our program yields, on a historic basis, a 97% success rate. To date, as you can see in our drilling program up there, we're 100% successful, and we've completed through the first half, I think, 81 wells. So it is -- it is concentrated on our existing acreage. We are buying some acreage up there, and it's certainly concentrated in and around our infrastructure, which is 2500 miles of our Cranberry pipeline system up there. We feel good about where we are, and we certainly feel good about the investment we made this last year in the first part of 2004. And the capacity expansion that we've had up there, we're now drilling into and seeing very positive results.

One further question on that. In addition to just the drilling costs, what kind of capital would you need to extend each over time in terms of gathering infrastructure to be able to completely drill up these locations?

I don't have that number at the -- at the tip of my tongue. We are -- if you look at the cost of drilling a well up there today, and you've got to look at assumptions on either tubulars, what they'll do in the future, what service costs will do in the future, but it's a little over $250,000 per well completed up there. And as we go through our accelerate, if you will, drilling program, compared to the past years, we will continue to add compression where we need to to de-bottleneck the production increases that we've created with our uptick in our drilling program. The 8 million that we spent this last year was -- expanded capacity by about 46 million cubic foot a day. The size of compression is solely dependent upon the operational pressures in the pipeline in the particular areas that we might have the bottleneck. And we'll spend anywhere from 100 something thousand dollars in a particular area, to eight or 900 thousand dollars for a large compressor in a particular area to maybe reduce the suction pressure. So it's kind of location dependent, if you will.

Okay. One last question for you on Canada. Any thoughts on what your drilling program would look like next year, or is it too early?

No, it's not really too early. We have some projects that are drillable, and we're putting together into our 2005 program for Canada. Have not finalized that process. My expectation is that the Canadian drilling program will look similar to what we have this year. We -- one thing we have done this year in our Canadian drilling program, we had purely obviously exploration wells to start out with. We've had success in our initial exploration well up there, and what we have done is peeled off one of our exploration wells to put in its place a couple of development wells. And we've also had a -- a unique opportunity around this discovery we've made to farm into some acreage, and we have moved a new well on our budget for 2004 to take advantage of that farm-in opportunity around our recent discovery. So -- but overall, the program is anticipated to be something similar to what we have in mind through 2004.

All right. Good. Thanks very much.

Thank you.

Your next question comes from John Herrlin from Merrill Lynch.

Was your CapEx break down between regions in the last quarter?

Let me let somebody -- I'll let Scott, when he can put his hands on that real quick, John.

John, from the drilling perspect -- I'll give you drilling dollars by region, and then kind of all of the other capital.

That's fine.

Appalacia 16, the west was 10, Gulf Coast 22, Canada 2,

That was all of it?

That was drilling and dry hole costs.

Okay.

Our total program was 75.

The rest infrastructure type stuff?

Yeah, seismic.

Okay. Next question is on people. Didn't somebody from the Gulf of Mexico region leave, if I recall correctly? And, you know, there are bodies in the street. Are you looking to hire?

John, what we've done right now, you might be aware of this, Mike Walen came to his current position, Senior VP of the entire co, from the Gulf Coast region. The Gulf Coast office is in the same location as our corporate office, and he has -- he has stepped in that role right now, and we've asked our really four key managering down there to step up and take a strong leadership role in direct communications with Mike. And at this stage, we are -- we are very comfortable on how the Gulf Coast region is running. We had a lot of work to do to prepare for this upcoming board meeting, and it is our plan, though, to kind of start our look both internally and externally to fill that slot.

Okay. Thank you.

You bet.

Again, I would like to remind everyone in order to ask a question, please press star then the number one on your telephone keypad. We'll pause again to compile the Q&A roster. Your next question comes from Larry Benedetto from Howard, Weil.

Good morning.

Hey, Larry.

Dan, what is the status of the facilities installation Breton Sound?

Breton Sound 41?

Yeah, uh-huh.

They have -- all the installation is in. They have pressure checked the pipeline, and that is in place. And I would anticipate just any day, Larry, that they're going to be purging the -- purging the lines and ramping up. I'm sure they'll bring on, you know, open well, one at a time, and -- but it is imminent. All of the -- all of the facilities and operations side is kind of been placed, and now it's just prepping to turn a valve.

Okay. And then two prospects, think you spoke ebout last conference call. One, Redfish Bay, which was a Tom Brown generated prospect, and the other was Osbourne Springs, I believe.

Okay. Redfish Bay, you might have thought of a Conbrown. It was the name of the prospect was Conbrown.

Conbrown. Okay.

Yeah. And we are in the the process -- we've completed that well, and the process of geting that thing lined out, the pipeline, and moving forward with that.

Okay.

And in the Osbourne Springs, we have the discover well out there. We are evaluating, and right now we have a 3-D crew shooting our Wind Dancer, and from going from Wind Dancer, we're going shoot a 3D over Osbourne Spring and utilize that information to just pick a sweet spots in that discovery.

And so you think possibly drilling there maybe fourth quarter?

Well, in Osborn Spring, Larry, with what we've seen from the BLM so far year to date, I gets the last conference call I did mention that we were hopeful that we might be able to get some drilling to take place out there before year-end. But in what we've seen in the BLM, and how rapidly they are moving, or slowly, I should say, we do not have optimism that they'll deliver any permits to us in Osbourne Spring. But we do, however, plan on drilling our program in Wind Dancer.

Great. Well, thanks a lot.

You bet, Larry.

Your next comes from George Frelinghoisen from Karl Frieshomer & Company.

Yes. You mentioned two high impact wells in Canada, and I just wondered whether you could elaborate on that in terms of total depths and when they'll be down and the like?

Well, we're currently drilling the Stoleguard prospect, and it's impactful in a sense on the total area and project area. We have a 16% working interest. Net exposure is, oh, George, I would say anywhere from 10 to 25 Bs, and we anticipate that to be down in about a month. Fairly deep wells. Yeah, that's the Stoleberg. And the Soldier prospect, we have a 20% working interest. That project exposure, I think, net to us, is going to be 15 to 30 Bs. Drilling will start in August, and I would -- I think that's a 35 to 50-day well.

All right. Thank you.

You bet.

Again, if you would like to to ask a question, please press star then the number one on your telephone keypad. We'll pause again to compile the Q&A roster. At this time, there are no further questions. Mr. Dinges, do you have any closing remarks?

Well, Jody, just again I appreciate the questions and I appreciate the interest in Cabot's program. I'm also pleased that we have began to get some recognition from the street on I think what we're able to deliver. And again, a company that can deliver organically, as our program will deliver, and also add the upside exposure in our program, I think is fairly unique, and we're optimistic that we're going to be able to deliver a program in the third and fourth quarters. If it's anywhere close to what we've been able to deliver if the first half, I'm going to be excited, and I think the shareholders will be excited, also. I'm fairly optimistic on the early exposure that I've seen on our 2005 program that we're putting together, and certainly in the third quarter we'll able to elaborate on that a little bit more in depth. But thank you for your time and interest, and look forward to our next visit.

Thank you. This concludes today Cabot Oil & Gas corporation's second quarter earnings call. You may now disconnect.