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2003 First Quarter Results Conference Call
Friday, April 25, 2003
Chaired by
Harold Korell
President, Chief Executive Officer and Chairman of the Board
Korell: Good morning, and thank you for joining us. With me today are Richard Lane, our Executive Vice President of Exploration and Production and Greg Kerley, our Chief Financial Officer.
If you have not received a copy of the press release announcing our first quarter results, you can call Sharon at (281) 618-4784 and she'll fax a copy to you. Also, I would like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our Securities and Exchange Commission filings. We also would warn you that these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.
Our first quarter results were marked by several significant achievements. Our quarterly earnings were the second highest in the Company's history, primarily due to high commodity prices that have helped the entire industry. And in March, we successfully completed the first follow-on equity offering in the Company's history, raising net proceeds of $103 million. The equity offering was very well received, and our stock continues to perform well, with a year-to-date return of over 17%. The offering significantly improved our balance sheet and our financial flexibility and has provided us the capital to accelerate the development program of our Overton Field in East Texas. The current drilling economics at our Overton Field are excellent and are generating a pre-tax present value index of well over $2.00 for each dollar that we invest.
Our results at the Overton Field have been very positive over the last two years. To date we have drilled 43 wells in the field with a 100% success rate. We believe that continued downspacing should allow us to drill at least 100 wells in the area over the next two years, which should lead to significant production and reserve growth. We are already beginning to see an increase in our daily production rate as we feel the impact of accelerating the drilling at Overton and as we continue to execute our capital plan in our other core operating areas.
Earlier this week our Board approved an increase in our E&P capital program to $150 million up from our original budget of $137 million. The increased capital investments are targeted toward drilling additional wells at Overton and for additional drilling in the Arkoma Basin in Arkansas. Richard will provide you with more details on these projects in a moment.
We have made excellent progress in executing our business strategy during the first quarter and we expect that 2003 will be a record year of financial and operating performance for Southwestern.
That concludes my comments. I'll now turn the teleconference over to Richard for an update of our E&P operations and then to Greg Kerley to discuss our financial results.
Lane: Thank you Harold and good morning. In the first quarter of 2003, we increased our activity in the Arkoma Basin and East Texas and participated in a total of 30 wells. Of these, fifteen were successful and thirteen were in progress at the end of the quarter. This well count is almost half of the 65 wells we drilled in all of 2002.
Production for the quarter was 8.9 Bcfe, down from 9.5 Bcfe in the fourth quarter of 2002 and 10.3 Bcfe in the first quarter of 2002. The 8.9 Bcfe of production is in the middle of the guidance range we provided in February. The year-on-year production decrease was due partially to the earlier decline in our South Louisiana properties and as a result of the sale of our Mid-Continent properties. As Harold mentioned, we are now seeing the positive effects of our increased drilling activity, and expect our second quarter production rate to be higher than our first quarter production and in line with the guidance we provided in February.
In the Arkoma Basin, we participated in ten wells in the first quarter, in contrast with the two wells that we drilled in the first quarter of last year. Of the ten wells, three were successful, two were dry, and five were still in progress. One successful well of note is our Yandell well located in the Ranger Anticline Area of Yell County, Arkansas. This well, which is currently on production, tested at a rate of 6.0 Mmcfpd from 145' of Upper Borum pay at a depth of approximately 5,500'. Southwestern operates this well with a 65% working interest. The Ranger Anticline Play continues to be a solid value-adding project, and has significant remaining development potential. Additionally in Arkansas, a new law has been passed by the state concerning drilling units. Act 964 provides operators in the state the ability to pursue multi-well development of original 640-acre units, applied for on a field-by-field basis, where it is supported by technical data. In general, we view this new legislation as positive for the Arkoma Basin. In the first quarter, we were able to successfully obtain regulatory approval to reduce well spacing from 640 acres per well to 80 acres per well in the Ranger Anticline Area. As a result, we have increased our planned 2003 drilling program in the area from two wells to seven wells. The Catlett #2-13, our second Ranger well this year, has reached total depth and is awaiting completion operations.
We continue our active workover program in the Arkoma Basin, with ten workovers in the first quarter alone. In 2003 we plan to participate in 60 workovers and will invest approximately $6.5 million in the program. A successful example from our program is the recompletion of the USA #1-10 to the Upper Borum "C" sand. Gross production from this well increased from 500 Mcfpd to 2,900 Mcfpd as a result of the workover.
In the first quarter, we drilled the second test well on our Midway Prospect in Logan County, Arkansas. Both wildcats were targeting the Spiro horizon at approximately 10,200'. We found sand in both wells, however it was poorly developed and tight. We are currently evaluating the results and data from these wells to determine the future exploration potential of the remaining acreage.
In the Permian Basin, we focused our drilling activity in our Cherry Canyon and Devonian plays. In the first quarter we drilled and completed our second and third horizontal wells in our Birds of Prey Cherry Canyon prospect in Eddy County, New Mexico. The Eagle #4-1 drilled a 1,650' horizontal section in the Cherry Canyon seven sand at approximately 4,800'. The Falcon #10-1 drilled a 1,480' horizontal section in the Cherry Canyon six sand at 4,900'. Both of these wells are currently on production. Including our first horizontal well, the Peregrine #1, drilled in mid 2002, our combined production is approximately 325 Bopd. We operate these three wells with a 100% working interest, and are currently planning to drill two additional wells this year.
At the time of our last teleconference, we were drilling our Jericho prospect in Lafayette Parish, Louisiana. This well targeted the Frio sands at 14,300'. The main objective sand was wet and the well was completed in a shallower zone. The Marg Vag zone at 10,000' is currently testing at 3.2 Mmcfpd and 192 Bopd with a flowing tubing pressure of 3,200 psi. Southwestern operates this completion with a 21% working interest. Also in Louisiana, we are currently drilling a sidetrack on our Shiloh prospect. This well is located in Vermilion Parish and targets the Cris R sand at 14,000'. The targeted zone was faulted out in the original wellbore. The sidetrack is designed to move the well's original bottom hole location and penetrate the objective sand. We estimate the sidetrack to be at total depth in approximately two weeks.
We expect to spud our second development well on our North Grosbec discovery in Assumption Parish within 30 days. Southwestern holds a 33% working interest in the Brown-Sonnier #1 which will target the P-10 sand at a depth of 17,200'. Current gross field production for North Grosbec is 15.4 MMcfpd and 550 Bopd.
Additionally in Louisiana, we are continuing to interpret the data from our 135 square mile Duck Lake 3-D seismic project. We have begun leasing state and fee lands under some of our prospects and we expect to spud two to three wells on this shoot this year, and have identified several additional leads that we expect will yield prospects for 2004.
Our next Southwest Louisiana exploration well will be our Coleburn Prospect located in Jefferson Parish. This well targets the Tex W sand at 12,700' and should spud during the second quarter. Southwestern will operate this well with a 50% working interest.
We have significantly increased our activity at Overton Field. In the first quarter, we drilled fourteen wells, of which ten are currently producing and the other four are in progress. It is interesting to note that in the first quarter of 2003 alone we have drilled almost as many wells at Overton as we did in all of 2002 and have maintained our 100% success rate. We are continuing to set production highs for the field as a result of the drilling program. At year-end, gross production from the field was approximately 27 MMcfpd and current production is approximately 43 Mmcfpd. We continue to employ new technology to lower our drilling time and costs and improve recoveries. In the first quarter, with one of the H&P flex rigs, we set a new record by taking only eighteen days from spud to total depth on the Arnold Gas Unit #2-3 well. This compares very favorably to the average drilling time of 27 days per well we achieved in 2002, which itself was down from an average of 35 days per well in 2001. At the beginning of 2003, we planned to drill a total of 47 wells at Overton this year. However, as a result of our improving efficiencies, we now anticipate the 2003 Overton program to be 53 total wells. The well costs, production rates and estimated ultimate recoveries of our first quarter wells are on track with our previous forecasts for this program. Overton Field is located in Smith County, Texas and produces from the Taylor series of sands in the Cotton Valley at approximately 12,000'. Southwestern holds an average 97% working interest in the field.
As Harold mentioned, we have increased our 2003 E&P capital budget from $137 million to $150 million. The majority of the increase will be directed to drilling at Overton, the Ranger Anticline, and the Birds of Prey project, some of our lower risk and highest PVI projects.
Our lease operating costs in the first quarter were $3.9 million or $0.42/Mcfe. This compares favorably to our fourth quarter 2002 costs of $4.8 million or $0.50/Mcfe, and first quarter 2002 costs of $4.5 million, which was $0.43/Mcfe. Our Mid-Continent assets represented our highest expense per unit of production properties. Divesting of these properties, coupled with the increasing production at Overton Field, will allow us to lower our full year 2003 LOE rate to the $0.31 to $0.35 per Mcfe range.
In summary, our first quarter results were in line with our expectations and our 2003 Plan. We have successfully implemented the planned increase in our drilling activity levels in our core areas and are experiencing strong commodity prices for our production. These factors, coupled with a favorable environment for drilling, completion and other field related costs, are allowing us to create and capture more value through our E&P program. We are very excited about the opportunities ahead of us for the remainder of the year.
I will now turn the teleconference over to Greg Kerley, who will discuss our financial results.
Kerley: Thank you, Richard and good morning. As Harold indicated, we had excellent financial results for the quarter driven in large part by high commodity prices. We reported net income of $13.6 million, or $.47 per share, for the first quarter, up from $6.7 million, or $.26 per share for the same period last year. Results for the quarter included an after-tax charge of $855,000 (or $0.03 per share) related to the adoption of Statement of Financial Accounting Standards No. 143, which deals with the recognition of asset retirement obligations.
Operating income and discretionary cash flow were $27.7 million and $36.7 million, respectively, during the first quarter compared to $16.8 million and $25.9 million for the first quarter last year.
Operating income from our exploration and production segment was $18.9 million, up from $7.3 million for the first quarter of 2002. The increase was primarily the result of higher gas and oil prices, partially offset by lower production volumes. Our realized gas price was $4.15 per Mcf for the first quarter compared to $2.76 during the first quarter of 2002. Our commodity hedging activities lowered our average gas price by $2.26 per Mcf during the first quarter of 2003, and on a comparative basis, our hedging activities had the effect of increasing our average gas price during the first quarter last year by $0.44 per Mcf. Our hedge position for the remainder of 2003 is unchanged from the detail provided in our Form 10-K; however, we have placed price collars on an additional 10 Bcf of natural gas in 2004 with an average floor price of $4.00 per Mcf and an average ceiling price of $6.66. Our detailed hedge position is included in our Form 10-Q filed yesterday.
Our E&P segment continues to benefit from low lease operating costs and we expect our lease operating costs per unit of production to continue to improve throughout the year. Our production taxes increased during the quarter due to higher commodity prices. And as we indicated in February, we expect our G&A expense to be higher throughout the year due to increased pension, insurance and salary costs.
Depreciation, depletion and amortization expense for the E&P segment was down by $1.5 million in the first quarter due to lower production volumes. Our amortization rate averaged $1.18 per Mcfe in the first quarter, compared to $1.16 in the prior-year period.
Our gas distribution segment reported operating income of $8.0 million in the first quarter of 2003, compared to $8.7 million in the first quarter of 2002. The decrease was primarily due to higher G&A, partially offset by increased deliveries due to colder weather during the first quarter of 2003. Weather during the quarter was 6% colder than normal and 11% colder than the same period last year. The increase in G&A was due to higher pension, insurance and salary costs. We filed an $11.0 million rate increase request with the Arkansas Public Service Commission in November of last year, and the Commission has scheduled a hearing date for our application of July 22nd, and we expect any increase granted will become effective in September of this year.
Our energy marketing efforts also provided approximately $700,000 in operating income during the first quarter of 2003, compared to approximately $800,000 for the same period last year. Our unregulated storage operations contributed $2.7 million to our improved operating results during the first quarter as a result of sales of gas in storage. Additionally, our results during the first quarter included a pre-tax gain of $1.5 million related to our NOARK partnership, compared to a loss of $200,000 for the same period in 2002. NOARK's results included a gain of $1.3 million on the sale of a 28-mile portion of NOARK's pipeline that had limited strategic value to the overall system.
Our capital investments for first three months of the year totaled $30.4 million, including $28.4 million for our exploration and production segment.
In March, we successfully completed the first follow-on equity offering in the Company's history. We sold approximately 9.5 million shares of our common stock raising aggregate net proceeds of $103 million. Initially, the proceeds were used to repay borrowings under our bank credit facility. We intend to reborrow the repaid amounts as necessary to fund the development of our Overton Field and for general corporate purposes. In total, we reduced our debt by over $117 million during the first quarter and reduced our debt to total capitalization ratio to 44% at March 31st, down from 66% at the end of 2002. Our total debt is expected to increase during the remainder of the year as we continue to implement our capital program, however we expect our debt to capitalization ratio to remain at approximately the same level as the equity in our balance sheet increases with our earnings.
That concludes my comments, so now we'll turn back to the operator who will explain the procedure for asking questions.
Questions and Answers |
1. I got on a little late. You maybe discussed this. But could you give us an update on Duck Lake, when the drilling will commence and what are the key couple of wells -- first couple of wells to focus on?
Lane: Sure, Van. It's Richard. We got that data set late last year and we're working it and continue to work it real aggressively. We've begun leasing under several ideas we have there, both state lands and fee lands and we're converting land that we had optioned into leases.
And as we said earlier, we're still pretty much on schedule. We think we'll spud two to three wells on that shoot in the second half of the year, and it also looks like we'll have some leads that will develop into prospects for 2004 as well.
2. OK. And the second question I have, East Texas drilling, you had that in the southern block where you had a couple of penetrations and I guess you have a few more now. How confident are you in the number of locations that you would have there and maybe the infill drilling there?
Lane: Yes, I think you're referring to what we call our map block. The additional wells that we've drilled there have been good. And we're encouraged to continue drilling down there. The abundance of wells this year will not be in that block, but will be in the main Overton block, and we're trying to satisfy our drilling obligation on that southern block and we'll keep doing that because the wells are doing fine.
3. Good morning, gentlemen. Nice job on the quarter. A few different questions for you. First off, Richard, I was wondering if you could provide a breakout in production by region, and maybe how that compares to fourth quarter results.
Lane: Sure. The first quarter production, again, to reiterate was 8.9 Bcfe. 4.5 of that was from the Arkoma basin, 2.1 from Overton and other east Texas, 1.1 Bcf from the Permian and 1.2 Bcf from the Gulf Coast.
And if you look back at the fourth quarter last year, of 9.5 Bcf, if you kind of reconcile the quarter on quarter, take away some of our mid-continent production representing about three-tenths of a Bcf, we do have a difference in just days in the quarters, which accounts for about two-tenths of a Bcf. So that just about gets you flat with the previous quarter.
4. OK. And in terms of by region, are most regions pretty flat quarter-over-quarter with Overton being up?
Lane: Overton is up. We're down about four-tenths at Arkoma and that's the biggest piece.
5. OK. Great. Second question, you mentioned the Coleburn well as your next well in South Louisiana. What is your reserve estimate on that well?
Lane: For all reserves, it's not a real large prospect thing. It's about in the 10 Bcfe-range, but it's risked or mitigated by some amplitude work we've done there. So it's not a real high-cost well and big potential, but we like the prospect.
6. OK. What was your working in interest again on that?
Lane: 50 percent.
7. Right. OK.
Lane: And Bcf gross.
8. And Bcf gross. OK. And then my final question, with the new legislation in Arkansas, can you give us some perspective on what you think that does to your overall drilling inventory in the entire basin?
Lane: Yes, you need to understand that it's not a sweeping, statewide rule change.
9. Right. You did it field by field.
Lane: That it is a field by field thing and it will be subject to approval by the Commission, and of course they'll be looking at the technical merits of the data you provide to do that. And so, for us as a company, there are some areas that it applies and there are some that it doesn't apply as much.
Certainly the Waveland and Ranger Anticline areas are good examples of where we think it applies, where the data definitely supports the down spacing, and the area is less mature, our fairway area is very mature and you know, what -we don't see kind of a broad sweeping effect in that area for us.
Korell: Having said that, this is Harold, I don't know, it's a little bit hard to predict the total outcome on this, but in most places where spacing rules have been changed and, if anything encourage more drilling rather than discourage it, there's usually been some activity associated with that in other states.
In Arkansas, each one of the areas will be slightly different but we consider it to be positive news.
10. Good afternoon or morning. Question on Overton Field, obviously the increase from 47 wells to 53 based on performance and efficiencies, a couple months ago you were on the road, you were talking about the hundred wells, would that then mean that next year those additional six wells got shifted just up to this year? Or is the hope and expectation then that as you continue to drill some on that southern block at Overton that you infill additional locations as we move forward?
Lane: There are a couple things at work here. One is that we did a small acquisition we didn't really talk about that, I think, today, but we did a small acquisition in the northern part of the Overton field. We call it Ful-Hill and we're moving on to it to drill -- are drilling on it now.
So that adds some additional space. But I think you're right, that we will move two or three wells that we had planned in next year's to this year. But there's also room to continue to drill if our map acreage to the south and Overton works out and then, we'll need to watch the performance of all of these wells out here.
Our reservoir engineering work to date would say that these wells do not drain 80 acres. We need to continue to monitor our production and reserve estimates. We're currently trying to drill this down to 80-acre spacing, so there's a potential beyond that possibly for some parts of the field to even have tighter spacing.
11. OK. And then in terms of the rate increase application with the hearing date in July, is the September date the point where you would hear what the final rate increase is -- would go towards? I know you filed for $11 million, but about how much of that would you receive?
Kerley: The new rates would be in effect by September, so we'll hear sometime between that hearing date of July 22nd and that date, and the Commission could wait until you get really close to that date or issue a order within just a few weeks, so it's hard to say.
12. OK, and then Greg, just one last number just on the- on the question on the cost, the G&A is a little bit under eight million. Did you say that you expect that to remain pretty flat throughout the year or should that increase a little bit just due to the pension and insurance costs that you mentioned?
Kerley: We think it will be relatively level throughout the year. We're accruing that on a quarterly basis based on what we expect the annual amounts to be, so that's our current expectation, Ron.
13. Gentlemen, and congratulations on a very nice quarter. If we could go back to the rate case in Arkansas, what has been the past history as far as granting rate relief in terms- with other utilities or even with yourself?
Kerley: Sure, Manny, this is Greg Kerley. The most recent experience we've seen has been that the Commission has had two other gas utilities in the state within this past year and they got kind of varied treatment. Both of them received an allowed return on equity that was lower than what we filed; we filed a 12.9 percent return on equity based on some testimony that a consultant filed for us that justified that high of a return, but the actual return authorized by the Commission has been closer to 10 percent. And what we've seen in those two different cases is one of the utilities received about 35 percent of what they requested ultimately. The other utility, the larger of the two, Arkla, received about 67, 68 percent of what they requested. If you, just from a standpoint on our filing of $11 million, if you adjusted that return down to 10 percent, they gave us the same return even though we think we're justified a higher return, that would make our filing about $8 million instead of $11 million, so that definitely has a big impact. So there's definitely a range and historically with the Commission, again it has been anywhere from, 50, 60, 70 percent has been kind of a typical historical range.
14. And the makeup of the current Commission, Greg, is what?
Kerley: There are three Commissioners; they have been appointed in the last, I guess just few years. I don't know all three people's names, but Sandy Hockstetter is the head of the Commission.
15. OK. So we'll wait 'til July or thereabouts and see on that side. Moving over to another area, have we had any contact with Moody's regarding reexamining our debt situation?
Kerley: We've had some initial contact with them to share the results; they're very pleased with, I think the-as was S&P with the offer, equity offering, and had some initial discussions with them that we'll be pushing forward with throughout the later months of this year to try to improve our rating with them. As you know, at S&P we're rated triple B, but with Moody's Ba2 and we think we're justified in definitely a higher rating from Moody's.
Operator: And that does conclude our question and answer session. Gentlemen, I'll turn the conference back over to you for final closing remarks.
Kerley: This is Greg Kerley. Thank you for joining us today and please feel free to call me or our manager of investor relations, Brad Sylvester, with any other questions that you may have or for other information you may need.