Coterra Energy Inc (CTRA) 2004 Q1 法說會逐字稿

Good morning. My name is Stacey and I will be your conference facilitator today. At this time I would like to welcome everyone to the Cabot Oil & Gas first-quarter earnings conference call. All lines have been placed on mute to prevent any background noise. (Operator Instructions). Thank you, Mr. Dinges, you may begin your conference.

Thank you, Stacey. Good morning. We appreciate you joining us for this first-quarter earnings teleconference call. With me today to answer any questions you may have are several members of our management team including -- Mike Walen, our Senior Vice President; our Scott Schroeder, our CFO; Jeff Hutton, our VP of Marketing; and Chuck Smyth, our VP Controller. As usual, before we start, our attorneys have asked that I share with you the following statement.

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 involves risk and uncertainties -- including but not limited to market factors, the market price of natural gas and oil, results of future drilling and marketing activity, future production costs, and other factors detailed in the Company's Securities and Exchange Commission filing -- all non-GAAP financial measures discussed during this teleconference call have been posted to our website at www.cabotog.com along with reconciliation to the most directly comparable GAAP financial measures.

As most of you are probably aware, last night, Cabot reported much improved first-quarter results from one year ago. As highlighted in the press release, we posted net income of $19 million or 59 cents per share, and discretionary cash flow of $72.3 million. This compares to a $39.2 million loss for last year's first quarter that was driven by two onetime events. We also had $67.6 million discretionary cash flow.

Comparing last year's normalized results to this year the Company earned slightly less on lower oil production and slightly higher expense levels, which both were forecast.

In regard to production, meeting our production guidance is a big key for Cabot. For the first quarter we were able to increase our natural gas production versus last year's first-quarter by 3 percent. The key region delivering this positive result was the Gulf Coast region. Made a bcf improvement, or a 15 percent increase between quarterly reported periods. The Gulf Coast improvement was a result of a very successful exportation play we have going in the Raymond (indiscernible) Field in South Texas. Here, Cabot has improved our net production from 5 million per day to 20 million per day in the field, and we're still drilling wells.

Also, our accelerated work over program contributed to this improvement.

In addition to the growth in natural gas production experienced in the first quarter, we have anticipated production yet to be turned in line from 9 successful wells throughout the region and 3 workovers we conducted in the Redfish Bay area. The timing of this production to be turned in line will be between June and November this year. When all this production is online it will add 30 to 35 million cubic feet equivalent net per day to our production.

The success we've had year to date is exactly what we were looking for to offset the decline we've previously mentioned regarding our original CL&F properties. Virtually all of the reduced oil production between comparable periods, which I previously mentioned, is a result of the CL&F decline.

In our West region, as we stayed stated in the press release and discussed in our most recent annual report, our production was down, as anticipated, due to our level of investment over the last several years. However, I'm encouraged we have made two, what we think, are significant exploration discoveries in the West. With these two discoveries, we do anticipate narrowing the GAAP. However much and how quick -- how much and how quick we can close the GAAP will depend on us securing permits and the balancing of our expedited development program we want to conduct with the government's desire to regulate the process.

The larger our development program, the more difficult it might be to secure all permits we want.

Because of our early success year to date, we are not knocking up slightly (ph) our full year production guidance which previously anticipated a slight decline to flat production year-over-year. Currently revising the upside of this range by about 1 percent. While we do believe there can be more upside to this figure, the timing related to the successes we've had year to date will be the key in beating this guidance.

The new details by region will be posted to our -- and, frankly, are already posted to our website.

Concerning pricing, we continue to be pleased with the commodity prices and their continued resiliency. (indiscernible) withdrawal season slightly above one TCF it would seem, under normal circumstances, that this level of storage would put some downward pressure on prices. However, as we know, there are certainly has been a paradigm shift. Future price of natural gas being influenced by many factors -- such as price of oil, demand levels, supply, alternative energy such as coal, Hydro -- when you combine all these factors, it seems to be a consensus though that gas prices will remain about above $5. We are encouraged with that.

On Cabot's pricing, our first quarter price realization improved over last year's comparable quarter by 15 percent for gas, and 11 cents per barrel for oil. The impact our hedge position had on prices reduced our natural gas realization by 38 cents to $5.21 Mcf, and oil realization by $4.03 to $30.99 per barrel.

Subsequent to the year-end teleconference in February, we had -- we have not added any additional hedges to our position. Our hedge volumes are posted on our website. We do not anticipate layering in any additional hedges volumes for 2004 unless we were successful in making a cost-effective acquisition. Where we would want to protect the economics of the deal.

We plan to continue to valuating the 2005 gas market where we're currently 28 percent hedged greater than $5. We will look at the white collars versus the swaps in order to preserve some of the upside, if in fact we do move into hedging additional volumes.

One final point on hedging and price realizations, since we've had some questions. The future impact of certain derivatives -- and I'm talking about those that do not qualify for hedge accounting, are included in revenues each reporting period. Because of this, you cannot simply divide gas or oil revenues by volume and get the realize price reflected in our press release. The future impact for hedges that do not qualify for hedge accounting resulted in a reduction to our revenue of 1.7 million for gas and $3.9 million for oil.

On operating expenses, I'm pleased report that operating expenses for the quarter are under what we budgeted -- yet they are slightly higher than when you compare year-over-year. We saw expenses less than budgets in both direct operations and expiration expenses due to our success.

However, some expenses were a little bit higher when impacted by the harsh winter weather as compared to last year. Plus a general increase in costs associated with contract labor, regulatory expense, and power and fuel expense. We do recognize that improvement can be made and will occur through lower absolute costs and/or higher volumes. We plan on working on both.

As anticipated, the Company was able to generate excess cash during the first quarter. Cash in the bank at March 31st was $64 million, and after reducing this number for all outstanding checks, the balance was $51.8 million as reflected in our Q.

We still anticipate generating excess cash flow this year, as we have done in the last two years. This excess could be used to fund the capital program expansion, increase our interest in existing wells, maybe make a small acquisition or repurchase shares.

The latest increase in our capital program was to cover the facilities associated with our Gulf Coast success in Breton (ph)Sound, our little (indiscernible) Bayou discovery and our other shelf successes -- and also to cover the increased cost we've seen in drilling and production casing associated with steel increases.

Because of the tough economics of the M&A market, especially examining our applied trading value per unit, we reinitiated our stock buyback program, which had been dormant since 1998 as our press release has indicated. We believe strongly in purchasing assets we know well. And making the best economic decision. When you look at Cabot stock, it is a very compelling investment -- particularly in light of the two recent industry mergers that were announced.

Our goal at a minimum -- and let me emphasize this -- at a minimum, is to repurchase as many shares as are being exercised or awarded through grants. So that there is no dilution occurring to our shareholders. Again, a goal of ours -- as a minimum.

ON operations, in April, we disclosed that the first quarter, we were 7 for 7 with our expiration program and 100 percent successful overall -- as the press release highlights. Our expiration win streak -- which we don't, didn't anticipate to last forever -- was ended with a dry hole in Berk Well at our Hannibal project. But we did start a new streak and followed up with success at our West Cameron 424, where we have a discovery. Which will be another well that will contribute to our production profile increase later this year.

We remain optimistic for the wells in our program for the remainder of the year. And specifically, for our second quarter we have the following wells on our docket which we consider fairly impactful. One, the offset to our 81 CL&F 81 discovery we've announced we're drilling. That's the CL&F 5-1. We have 75 percent interest in that well. That's currently drilling our state track 281 -- excuse me -- down in Redfish Bay. That is our John (ph) Brown Prospect. We have 75 percent of that. That is also currently drilling.

We have our Soldier prospect in Canada. It's following up from -- that will be our second exploration well in Canada. Our first well, as we previously announced, was a discovery. We have 40 percent in this particular Canadian well, and it will spud in June.

We have two Rocky Mountain prospects -- Corral Creek -- and we have 63 percent and we have Gold Nugget in the Wind River basin where we have 75 percent. We anticipate both of those wells to spud in May.

If you take a combined look at these wells, in grow sense, it's 190 to 400 plus bcf unrisked. In the net sense it is 80 to 200 plus bcf net unrisked to Cabot. That is a healthy exposure on Cabot when you look at the impact it's going to have, and exposure we give our shareholders. It's one of the attractive things about Cabot, when you can look at the consistency at low-risk drilling we have in the East. And also be able to have the upside exposure that these type of wells will give us.

I'm pleased with how our program has come together this year. Particularly pleased with our year-to-date drilling success we have had. When you combined this level of success with where we find ourselves financially, and our continuing progress in operations, I believe Cabot finds itself in the best position that it has been in since it's public beginning.

With that, I will close my comments and I will open up the call for questions, Stacey.

(Operator Instructions). Bryan Singer, Goldman Sachs.

A couple of questions -- first, with regards to the production guidance, could you talk about what you're kind of assuming on the low end and the high end of the range in the fourth quarter? Especially with regards to the Gulf Coast? And then also with regards to the Appalachia, with a step up between a third quarter and the fourth quarter?

We have, of course, we posted the guidance out there and we have changed the mix of our guidance a little bit. And that is simply really a reflection of a timing issue. And, later in the year you'll see, going into the third quarter and fourth quarter, a reflection of the success that we have had in layering in, now, an actual profile versus a risk profile to our level.

In looking at our guidance, and in really just let's just take exit volumes right now. I would expect exit volumes on an equivalent basis to be somewhere between -- on the low side -- 248 250 -- to a high side -- 260 to 265 equivalent. Okay?

When you look at layering in some of the success that we have had between June and November, the June wells will be our CL&F, 81, some of the work over wells that we have in Redfish Bay, the Raymond Deal wells, down in Willipy (ph) County, down in South Texas Canada, kind of layer in as we can complete and hookup. So, they will be staggered throughout the process. And we have expectations that Breton Sound will come on in June or July. Its semi moving targets. Then we have a couple of -- Eugene Island 280 and Eugene Island 142 successes will be October and November, respectively.

Great. With regard to the second quarter, was there a reduction in the Gulf Coast guidance. Is that the timing issue as you mentioned that transferred to later in the year?

Exactly.

Okay. And given the recent successes, should we expect any changes -- any potential decreases in the DD&A rate?

You know, later in the year if -- on a per unit basis -- it will be similar to what we forecast. It will be in the fairway, I'm fairly confident, Brian.

Okay, thank you.

Ellen Hannan, Bear Stearns.

Just a couple of questions to follow up. The unrisked net reserves potential that you talked about -- does that include your Canadian prospect? Or is that just the two Rocky Mountain prospects?

No, that includes the one Canadian prospect. That does not include the success that we've had up there. And you're talking about the unrisked guidance I gave, Helen? I couldn't hear you very well.

Yes. You know, the 80 to 200 net bcfe on risks.

That only includes the Soldier prospect.

It -- does it include the two Rocky Mountain prospects as well -- the Gold Nugget and --?

Yes it does.

Okay. Can you give us just a little bit more color on what you think you have in Canada and what kind of inventory you think you may be building, etc.?

Yes, Helen, I will let -- Mike is with our board meeting yesterday and having the opportunity to visit with Les Watson, our VP up there who manages our two joint ventures. Mike had a chance to visit with him, and I'll Mike Walen kind of ad lib on that.

First, Helen, we're extremely excited about our Musk Grove discovery up there -- that's the well we drilled earlier this year. We have completed the top sand -- I'm sorry, the base sand. And got a good rate. We're waiting on pipeline now. We plan to start development on that. We have two wells scheduled to startup later on this year offsetting that discovery. And we will -- if we have continued success, we will continue to develop that leasehold.

In addition to that, Dan mentioned we're going to be drilling the Soldier Well in June -- (indiscernible) well in June. Then we also have three other impact-type prospects that we will be looking to spud in the summertime, and into the early fall. That would be our Akin Creek well -- that's really a re-entry of a bypass well and an area of shallow -- shallower production. And our Skullberg (ph) well -- we spudded in May. And our Cypress re-entry which is a retype play up not too far up from (indiscernible) that we will be spudding this fall.

All of those -- the Skullberg and the Cypress are large potential prospects. Up in the gross type of numbers of 50 to 100 b type of prospects.

Great. Thanks very much.

(Operator Instructions). Frank Bracken, Jefferies & Co.

You have (indiscernible) -- you mentioned (indiscernible) 424 as a discovery, but didn't line it out in your progression of production increments. Could you give us a little more color there as to your expectations on timing and potential rate?

Yeah, Frank, we didn't put it in our guidance at this stage because we just recently had logged that well. But we are developing our production plan at this time. It is -- I won't say remote, because it is now on the shelf -- there's not anything remote from a pipeline. But we will have anywhere from 7 to 10 miles of pipe to lay out there, and scheduling that and the timing is being developed right now. So, I would say, at best, Frank, that we would see that online probably December or so.

Okay. And any -- is this a 10 million a day well, a 20 million a day well?

Yeah. We will get a good rate out of it from a reserve standpoint. It's not a huge discovery -- not as large as we had anticipated. But as far as rate, very, very clean sands and typical of the shelf Gulf of Mexico -- it will come at us pretty quick.

Great. Thanks very much.

At this time Sir, there are no further questions.

Okay, well, I appreciate that, and appreciate the interest, (indiscernible) easy on me today. And, just to reiterate, I'm pleased with where Cabot finds itself today. I'm not content with progress we've made. We plan on making further strides. And I'm also pleased though that I think Cabot is starting to get a little bit of recognition for the value that we have in our asset base.

I think we can continue to demonstrate added value, and I think once we get out a little bit more this year, since we were not outlast year and we tell the Cabot story a little bit more. I think we will continue to see a lot of interest in what we have to offer.

If we can continue with the level of success we have had year-to-date and our 2004 program, and continue that for the remainder of the year, I'm sure we will continue to add substantial value for our shareholders. Again, appreciate your interest and look forward to our next visit. Thanks.

Thank you for participating in today's conference. You may now disconnect.