FILED BY ENTERPRISE PRODUCTS PARTNERS L.P.
PURSUANT TO RULE 425 UNDER THE SECURITIES ACT OF 1933, AS AMENDED
AND DEEMED FILED PURSUANT TO RULE 14A-12 AND RULE 14D-2(b)
OF THE SECURITIES EXCHANGE ACT OF 1934
SUBJECT COMPANY: GULFTERRA ENERGY PARTNERS, L.P.
COMMISSION FILE NO.: 1-11680
ENTERPRISE PRODUCTS PARTNERS L.P. (“ENTERPRISE”) AND GULFTERRA ENERGY PARTNERS, L.P. (“GULFTERRA”) WILL FILE A JOINT PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS WITH THE SECURITIES AND EXCHANGE COMMISSION. INVESTORS AND SECURITY HOLDERS ARE URGED TO READ CAREFULLY THE JOINT PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION REGARDING ENTERPRISE, GULFTERRA AND THE MERGER. A DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS WILL BE SENT TO SECURITY HOLDERS OF ENTERPRISE AND GULFTERRA SEEKING THEIR APPROVAL OF THE MERGER TRANSACTIONS. INVESTORS AND SECURITY HOLDERS MAY OBTAIN A FREE COPY OF THE JOINT PROXY STATEMENT/PROSPECTUS (WHEN IT IS AVAILABLE) AND OTHER RELEVANT DOCUMENTS CONTAINING INFORMATION ABOUT ENTERPRISE AND GULFTERRA AT THE SEC’S WEB SITE AT WWW.SEC.GOV. COPIES OF THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS AND THE SEC FILINGS THAT WILL BE INCORPORATED BY REFERENCE IN THE JOINT PROXY STATEMENT/PROSPECTUS MAY ALSO BE OBTAINED FOR FREE BY DIRECTING A REQUEST TO THE RESPECTIVE PARTNERSHIPS.
ENTERPRISE AND GULFTERRA AND THE OFFICERS AND DIRECTORS OF THEIR RESPECTIVE GENERAL PARTNERS MAY BE DEEMED TO BE PARTICIPANTS IN THE SOLICITATION OF PROXIES FROM THEIR SECURITY HOLDERS. INFORMATION ABOUT THESE PERSONS CAN BE FOUND IN ENTERPRISE’S AND GULFTERRA’S RESPECTIVE ANNUAL REPORTS ON FORM 10-K FILED WITH THE SEC AND IN THE SCHEDULE 13D FILED BY DAN L. DUNCAN WITH THE SEC, AS AMENDED ON DECEMBER 18, 2003, AND ADDITIONAL INFORMATION ABOUT SUCH PERSONS MAY BE OBTAINED FROM THE JOINT PROXY STATEMENT/PROSPECTUS WHEN IT BECOMES AVAILABLE.
Enterprise Products Partners L.P. (“Enterprise”) is filing a CCBN StreetEvents transcript of its February 3, 2004 earnings release conference call in which certain aspects of the proposed merger between Enterprise and GulfTerra Energy Partners, L.P. were discussed.
CCBN StreetEvents Conference Call Transcript
EPD — Q4 2003 Enterprise Products Partners L.P. Earnings Conference Call
Event Date/Time: Feb. 03. 2004 / 10:00AM ET
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Randy Burkhalter
Enterprise Products Partners L.P.
Dub Andras
Enterprise Products Partners L.P. — President and CEO
Mike Creel
Enterprise Products Partners L.P. — Executive Vice President and CFO
James Teague
Enterprise Products Partners L.P. — Executive Vice President
Dan Duncan
Enterprise Products Partners L.P. — Chairman of the Board
David Fleischer
Anderson — Analyst
John Edwards
Deutsche Banc — Analyst
David Macrarrone
Goldman Sachs — Analyst
Eric Olson
Sanders Morris Harris — Analyst
Ron Londe
A.G. Edwards — Analyst
David LaBonte
Salomon Smith Barney — Analyst
Dennis Coleman
Banc of America Securities — Analyst
Brian Watson
RBC Capital Markets — Analyst
Gil Alexander
Darphil Associates — Analyst
John Tysseland
Raymond James — Analyst
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Hello and welcome to the Enterprise Products Partners Earnings Conference Call. Following today’s presentation, there will be a formal question and answer session and instructions will be given at that time. Until then, all lines will remain in listen-only mode. I would now like to introduce today’s host, Mr. Randy Burkhalter. Sir, you may begin.
Thank you. Good morning and welcome to the Enterprise Products Partners conference call to discuss earnings for the fourth quarter of 2003. This morning, Dub Andras, Enterprise’s President and CEO will lead the call and Mike Creel, Executive Vice President and Chief Financial Officer will follow with financial discussions. Included on the call today from Enterprise are Dan Duncan, our Chairman and co-founder and Jim Teague, Executive Vice President responsible for the partnership’s NGL assets. Afterwards, we’ll open the call up for your questions.
During this call, we’ll make forward-looking statements within the meaning of Section 21-E of the Securities and Exchange Act of 1934, based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise’s management. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the Securities and Exchange Commission for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made in the call.
With that, I’ll turn the call over to Dub.
Good morning. Thank you for joining us. Before we discuss the details of our earnings for the fourth quarter I would like to spend a few minutes to provide you with an update of our business additions for our partnership for the fourth quarter and what we see thus far in the first quarter of 2004.
As we mentioned on our previous calls of June and July of 2003, we were surprised by the severity of the decrease and demand for ethane. A number of unusual events coincided for the lowest demand for ethane since 1945. At that time, we did not believe the petrochemical industry’s low production rate and low demand for ethane were sustainable even with the weakness in the U.S. manufacturing sector.
Since that time, we’ve seen steady improvement in the industry’s production rates and in its demand for ethane. The ethane demand increased from 574,000 barrels per day in June and July to 661,000 barrels per day in the third quarter and 719,000 barrels per day in the fourth quarter. So far in January, demand remained solid at approximately 700,000 barrels per day despite natural gas prices that averaged $6.15.
The increase in demand for ethane has been driven by increased demand for ethylene and its derivatives, primarily polyethylene. Many of our customers have publicly commented on the improved demand for their products both domestically and globally, due to the strengthening economies. They have noted volume growth and the ability to pass through price increases which more than offset higher feedstock costs and energy costs.
According to Pace Hodson, ethylene production rates have increased from an annual run rate of 48.8 billion pounds in June and July to 52.7 billion pounds for the last three months, an 8% increase. At this level of production, the petrochemical industry has less flexibility in its choice of feedstocks and requires the additional ethane even with the relatively high costs of natural gas compared to crude oil derivatives. This increased demand has been the biggest reason for improved natural gas processing, fractionation and pipeline economics.
On the U.S. Gulf Coast, the indicative natural gas processing spread, which is the equivalent value of Mont Belvieu NGLs versus Henry Hub gas, increased from 4 cents per gallon in the second quarter of 2003 to 10 cents in the third quarter and 17 cents in the fourth quarter. In January the spread was approximately 15 cents. This improvement has led to our processing plants and those operated by others to increase their extraction of NGLs from natural gas. As a result, we have seen an increase in NGL volumes to our fractionators and pipelines. Though still lower than our historical averages, during the fourth quarter, we saw some of the highest operating rates of 2003.
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Since the second quarter of 2003, our Mid-America and Seminole pipeline systems have been challenged by the occasionally poor economics of extracting ethane from natural gas in the southwest Wyoming region of the Rockies. During these periods, the majority of the ethane is left in the natural gas stream and is not available for our pipelines. In the third quarter, these pipelines in aggregate lost about 50,000 barrels per day when ethane processing economics bottomed out at an average of a negative 2.4 cents per gallon. In the fourth quarter, the economics improved to break even. To promote the natural gas processing in this region to extract more ethane and increase the volumes flowing to our pipeline, we began to offer a discounted tariff. This incentive resulted in increased volumes and incremental margins for the pipelines.
In January, with the increased demand for ethane, the benefit for extracting ethane in southwest Wyoming averaged a positive 2 cents per gallon at full tariff. Effective February 1, 2004, we’ve instituted a FERC-approved incentive tariff for this pipeline system which in periods of weak ethane processing economics will adjust to offer processors enough of a discount in the pipeline transportation rate to extract ethane while providing our pipelines with the highest incremental margins. The amount of the tariff automatically adjusts on a daily basis to promote the highest utilization and margins for Mid-America and Seminole pipelines. In periods when ethane economics supports extractions, no discounts are given. This tariff should improve our cash flow during periods when ethane would not otherwise be extracted.
To recap, the business environment has improved dramatically since the second and third quarters of 2003. Customers have projected increased demand for their products in 2004 as a result of improving conditions both globally and in North America.
Some of our customers have recently projected demand growth for polyethylene in 2004 up to 7%. This leads us to believe we have emerged from one of the toughest business cycles we’ve seen in quite sometime. Also, once we’ve completed the merger with GulfTerra, the complimentary nature of each of our partnerships operating cash flow profiles will reduce the overall level of gas fluctuations from the combined partnerships.
Now, let me take a minute to update you on our organic growth in the Deepwater, Gulf of Mexico and in the rocky mountain area. In the Gulf, about 3,000 barrels per day of NGLs began flowing to our downstream facilities from Medusa and Matterhorn. We expect to see another 18,000 barrels per day from Marco Polo and Nakika when they reach peak operating rates later in 2004. Another 5,000 barrels per day is expected to come on stream in the late fourth quarter from BP’s Southern Green Canyon discoveries, Holstein and Mad Dog. Also in the fourth quarter of the year, we expect to see another 2,000 barrels per day from Devon’s share of the Magnolia discovery in the Garden Banks area.
Looking out farther into 2005, we expect to receive approximately 30,000 barrels per day of rich NGLs from BP’s huge discoveries in Atlantis and Thunder Horse. Turning to the Rocky Mountains, we will expect to receive an additional 8,000 barrels per day of propane and heavies as a result of Williams expanding its plant in southwest Wyoming. This is expected to start flowing in March.
I will now turn the call over to Mike Creel who will be reviewing the quarter in greater detail. Mike?
First, let’s review the operating results of our business segments.
The pipeline segment’s gross operating margin in the fourth quarter 2003 increased by 5.4 million to $72 million from $66.6 million in the third quarter of 2003. This improvement was primarily due to a $3.5 million increase in operating margin for the Mid-America and Seminole pipelines, largely as a result of the 53,000 barrel per day increase in volume and also as a result of the $4.4 million increase of margin from our NGL import/export terminal. This was partially offset by a seasonal decrease in operating margin at the Louisiana intrastate gas pipelines of $1.3 million.
Pipeline segment margins for fourth quarter of 2002 were $86.2 million. The $14.2 million decrease from the fourth quarter 2002 was due to a $14.8 million decrease for operating margins in Mid- America and Seminole pipelines, as well as a favorable rate case settlement reported in the fourth quarter of 2002. These decreases were partially offset by increased margins in the fourth quarter of 2003 from our NGL export terminal, NGL storage facilities and the Lou-Tex NGL and petrochemical pipelines.
Of the $14.8 million decrease in Mid-America and Seminole, $6.1 million was due to a 74,000 barrel per day decrease in aggregate volumes; 2.8 million was from pipeline integrity expenses incurred in 2003; and 1.4 million was due to administrative type expenses that are now allocated directly to the pipelines. During the fourth quarter of 2002, these types of expenses were included in the $6 million per quarter transition services fee that we paid to Williams that was included in G&A expense.
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Volumes in the pipeline segment were slightly less than expected during the fourth quarter of 2003 due to scheduled NGL export shipments that were canceled. While this reduced volumes at both the export terminal and Channel Pipeline system, it did not significantly affect our operating margin because we collected demand fees regardless of whether the facility was used.
Gross operating margins for the fractionation segment increased by $6.7 million from $30.6 million dollars in the third quarter of 2003 to $37.3 million in the fourth quarter of 2003. This increase was due to increased margin and volume in the NGL and propylene fractionation business that more than offset the effect of a 7,000 barrel a day decrease in isomerization volumes.
During the most recent quarter, we completed the expansion of our Norco fractionator to 75,000 barrels per day of capacity. In order to complete this expansion, we had to take the fractionator down almost the entire month of October. During this time, volumes were diverted to our Promix fractionation facility.
Fractionation gross operating margin for the fourth quarter of 2003 increased $1.1 million dollars over the fourth quarter of 2002. Again, increased margins from the NGL and propylene fractionation businesses more than offset the decrease in margin from the isomerization business. The operating margin for the fractionation segment for the fourth quarter of 2003 was reduced by $1.2 million for an asset impairment charge related to our 6,000 barrel per day fractionator in Mississippi.
The processing segment reported gross operating margin of $5 million for the fourth quarter 2003 compared to a loss of $6.9 million in the third quarter of 2003. During the quarter this segment benefited from improved gas processing margins that resulted in a 9,000 barrel per day increase in equity NGL production to 66,000 barrels per day.
The biggest disappointment for the quarter was the performance of our octane enhancement segment that reported a loss in gross operating margin of $4.8 million compared to a positive margin of 1.3 million in the third quarter of 2003, excluding the $22.5 million asset impairment charge recorded during that period. During the fourth quarter of 2002, the octane enhancement segment reported gross operating margin of $1.5 million. The decrease in margin is attributable to a decrease in domestic MTBE due to the phase out of this additive in California, New York and Connecticut at the beginning of this year. The lower domestic demand for MTBE combined with the effect of high natural gas prices on feedstock and operating costs resulted in significantly lower margins in this business.
We’re in the process of modifying this facility to produce iso-octane, another high octane motor gasoline additive that will be needed as a partial replacement for MTBE. This modification will take longer than we originally expected but should be completed by the end of the third quarter. Until this modification is complete, we will produce MTBE, or isobutylene, another gasoline additive based on marginal economics.
Depreciation expense was $31.9 million for the fourth quarter 2003 compared to 28.3 million in the third quarter of 2003 and 27.5 million in the fourth quarter of 2002. This increase was due in part to the completion of the number of capital projects during 2003 that was closed for accounting purposes in the fourth quarter and also as a result of increased ownership interests in the octane enhancement facility and the Wilprise and Tri-States pipelines. As a result of owning more than 50% of these facilities, we now consolidate them in our financial results. Previously, since we owned less than 50%, we accounted for these facilities under the equity method of accounting. Based on the assets we owned at the end of 2003, we expect depreciation expense to be approximately $26.8 million per quarter this year.
G&A expense for the fourth quarter of 2003 was $8.6 million compared to 7.4 million for the third quarter of 2003 and 14.9 million for the fourth quarter of 2002. Included in G&A for the fourth quarter of 2002 was $6 million of expense reflecting payments to Williams for providing transition services during the fourth quarter of 2002 with respect to Mid-America and Seminole pipelines. Since taking over operation of these pipelines effective February 1, 2003, some of these expenses that were included in the transition services fee are now recorded against the operating margin of these pipelines.
Interest expense in the fourth quarter of 2003 was $32.8 million compared to $32.6 million in the third quarter of 2003 and $33.3 million for the fourth quarter of 2002.
Net income for the quarter was $34.4 million, or 13 cents per unit. That’s 14 cents per unit without the asset impairment charge. This compares to net income of $55.5 million or 28 cents per unit for the fourth quarter of last year.
Distributable cash flow was $68.5 million for the fourth quarter of 2003 and for the full year distributable cash flow was $268.5 million.
At December 31, 2003, total debt to total capitalization was 54% based on debt of approximately $2.1 billion. In terms of liquidity, we had $314 million of availability under our bank credit facilities and $30 million cash on hand.
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Many of our fixed income investors and banks use a debt to last 12 month EBITDA ratio to measure leverage. To calculate this ratio, begin with EBITDA for the 12 months ended December 31, 2003 of $366.4 million. From this, subtract earnings from unconsolidated affiliates during this period of $14 million and add actual cash distributions received from unconsolidated affiliates during this period of $31.9 million. Also add $36.6 million to reflect a full year of EBITDA or cash distributions from acquisitions that we completed during 2003 but that are not included in the numbers above. This includes $35 million from our 50% ownership interest in the general partner of GulfTerra as if we had owned it for the entire year for 2003. The sum of this calculation is $469.4 million dollars. Dividing this into our debt on December 31, 2003 of $2.1 billion results in a debt for the last 12 months adjusted EBITDA ratio of approximately 4.57 times.
With that, we’ll now open up the call for questions.
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Thank you. If you would like to ask a question, please press star one on your telephone touchpad. If you are using speaker equipment, you may need to lift the hand set prior to pressing star one. To cancel or withdraw your question, press star two. Our first question comes from David Fleischer of Anderson.
Two different questions perhaps here. First of all, NGL marketing in processing hurt you in the fourth quarter. I was wondering if you could give us a little better update on what the current dynamics of that business are and how you might be able to reduce that volatility?
Thank you for the question, David. I’ll let Jim Teague answer that question, who’s in control of our marketing facilities. Jim?
Could you repeat that question?
Could you repeat the question one more time?
Yeah. The NGL marketing area portion of processing hurt you in the fractionation area there, and so I’m wondering what the current — you identified that in your write up. I’m wondering what the current dynamics are in that marketing business and, you know with, that volatility, I’m wondering how you could reduce the volatility in the future?
One of the things we’ve seen with the light propane season this year is that it affected us in terms of our wholesale propane marketing. That’s kicked in rather heavily as we got into December, so we should see improved results of that going forward into the first quarter. That’s one of the primary areas. In terms of decreasing the volatility, we’re becoming much more focused in our asset people working together with our marketing people. Remember, that our primary function of our whole marketing operation is to pull products through our asset base in our pipelines, our fractionators, our processing plants. We brought in a new leader of that whole marketing area. Our whole focus is — has evolved to being a support activity that pulls products through our asset base. They do this by buying product that’s at the tailgate of the processing plant, selling it at the tailgate of the fractionator, booking the delta, and the like.
So by its nature then, are you as long as you keep, you know, with that approach, are you not destined to suffering weak markets and have, you know, better periods and strong markets, it’s just the nature of that business? Is that what you are saying?
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Yeah, that’s what our objective is, David.
David, this is Dan Duncan. Our basic concept of marketing, we do no marketing per se where we go out and buy product on a speculative basis and sell product on a speculative basis. All of our marketing as Jim explained to you, basically it’s a value added service. We buy products that go through our pipeline or through our storage or our fractionators, so it’s only set up as a support group that makes our assets make the money. So most of this so-called marketing expertise moves volumes into our pipelines and we get value added just like BEF does to include the motor gasoline. We’re not in the marketing business per se to try to make money at that.
What happens sometimes is if you’ve got real increase in prices then you’ll end up with marketing profits only because the inventories you have in front of your plants and all of a sudden those inventories are much more than they were at the end of a year versus the beginning of the year. At the same token, you can have that same type of product you can actually move if the prices are worth less than at the end of the year than the beginning of the year. The marketing per se, we’re not in the business.
Right.
Of speculating in the marketing business.
I understand. Second question totally separate, if I can. I’d love to talk about future interest expense and, you know, particularly an interest rate environment that looks like it may start to rise now. You’ve — on a fixed floating segment had, you know, different proportion of — a higher proportion of fixed versus floating, and I’m wondering, you know, how you view that today, what your thought process is, and, you know, particularly as you look at an Enterprise, GulfTerra coming into your segment with higher cost debt from there, if you have anything you can talk about at this point about, you know, your ability to lower that debt cost as well? What your average cost of debt might be in ‘04.
David this is Dub. What we’ve got is pretty much different from most MLP’s. We’re at a very high fixed rate of return — fixed interest rate. We don’t have a lot of debt that is floating. But let me have Mike expand on that with where we want to be with GulfTerra.
Yeah, David. We’ve got today roughly 70% of our debt is fixed rate. A good portion of the floating rate debt is related to our acquisitions facility for the GulfTerra general partner. We do expect to pay that off here in the first half with an equity offering.
Clearly, with the closing of the GulfTerra transaction, there is a lot of opportunity for interest savings on a combined basis. We had structured the transaction and expect to close it in such a way that the GulfTerra debt will remain under GulfTerra and will be structurally subordinated to our debt. We do expect to launch a debt tender for the GulfTerra debt just prior to closing, and we expect to be able to get that debt back in at a reasonable cost and refinance it in this low interest rate environment.
I think going forward, our view would be, again, depending on where we are in the interest rate cycle and where the economics are at the time to maintain the floating debt of about 30 to 40% of our total debt. Clearly, if we’re in the market raising debt and expect interest rates to move up in the near future, we tend to stay a little bit more on the fixed side. Conversely, if we expected interest rates
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to decline, we’d lean more towards the floating rate side. We’ll have probably a more conservative debt structure than most MLP’s and certainly it’s something that we’ve done in the past and conservative with respect to the fixed to floating rate mix.
Okay, thank you.
Thank you. Our next question comes from John Edwards of Deutsche Banc.
Yeah, good morning. You were talking about the discount on the tariff earlier. Could you put a little more detail on that, you know, how much of a discount and for how long? You were talking about how it floated and it varied under this discount. I didn’t catch all of the details how that worked. If you could maybe go over that again or explain it a little more.
The incentive tariff that we’ve instituted, let me just give you an example of that is the best way to handle it. The pipeline tariff is approximately 7 cents. If the economics of attracting ethane in the Rocky Mountain area, let’s just pick Wyoming as an example. If they have a BTU value of the gas that doesn’t allow for a 7 cent tariff and let’s say it would allow for a 6 cent tariff, we lower that tariff to the processor to where he will not lose money. As a matter of fact, the incentive tariff will support that they make money up first is the BTU value of the gas by whatever means that we have to do it. If we lower the tariff by a penny or penny and a half, we still have a substantial incremental profits in the pipeline, so its good for both processor and the pipeline to extract that ethane and bring it to the market.
Okay. So you will --
And it’s done on a daily basis, John, so, you know it’s very flexible. We can change that each day to fit the processor.
Okay. So you basically agreed with the customers that if they’re making money they’ll pay the full tariff, but the agreement is if they’re being stressed, the tariff will automatically adjust. So you are in daily contact with them --
We guarantee that they will make money, that’s right by giving them the reduction of the tariff.
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And then could you explain where the where the impairments are booked, the 1.2 million impairment charge. What business unit did that come from?
That was in the fractionation segment. That was an impairment charge for the Petal fractionator in Mississippi.
That’s our fractionator in Mississippi. What led to the impairment charge is it’s been running at low rates due to the production along that pipeline and fractionation facility, so we’ve reduced the book value of that by a million to $1.2 million.
Okay. And then any further update on the merger with GulfTerra, you know, when you expect the equity offering to come and when you think the approval will be complete, that sort of thing?
I think on the equity offering, as Mike said, we’ll be doing that during the first half of the year. We can’t talk about the specific dates on that.
The other activity that points to GulfTerra of course is the FTC work is moving smoothly. We still think we’ll see a conclusion here in the second half of the year. We can’t pinpoint exactly the month yet obviously, but sometime hopefully in the mid to late third quarter would be our estimate at the present time. But we’ll still stick with sometime in the second half as far as the FTC works.
We’re busy doing the work of defining the management of the company that we will have when we get the merger completed, and the importance of the role that each company will be playing in that top management. Then once we get that defined, we’ll use that management organization to get the synergies that we feel we are pretty confident in achieving, which is we estimate to be approximately $30 million. We think that we do this well and we’ll have that $30 million synergies upon closing. We won’t have a six month to a year transition period after we accomplish that.
So everything’s moving smoothly. We think we’re probably a little ahead of schedule. Maybe a week or so ahead of schedule that we set up there in December to get these things accomplished on a monthly basis.
Okay, thank you very much.
Thank you. Our next question comes from David Maccarrone of Goldman Sachs.
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I was hoping to expand a little on John’s question about the equity offering with regard to any more specifics on the size and timing of the offering or offerings, and along those lines, give us an update on your confidence level in maintaining an investment grade credit rating following the deal with GulfTerra.
Sure, David. One of the problems that we’ve got, as far as timing, it’s really a transaction — if it were simply the GulfTerra transaction, it would be pretty simple to do the proforma financial statements that are required. Unfortunately, or fortunately, depending on your view, we’re also doing a separate transaction with El Paso where we’re acquiring some of their south Texas plants. As a result, in our proformas, we also have proforma those financial statements as well. GulfTerra has not owned those plants for the periods required to be covered by the proforma financial statements so they are in the process of preparing the financial statements and having them audited by PriceWaterhouseCoopers. So we’re in a position where we’re waiting on those financial statements. So the timing is a little bit up in the air, but obviously, we don’t think we’re too far off track.
With respect to the potential rating of our debt after the transaction has closed, we have structured it in a way where we think that we will have very sound financial ratios and metrics. We believe that we should be able to maintain our investment grade credit rating. We have not had the opportunity to really sit down and go over those plans in great detail, although we plan to do that in the next several weeks.
Okay. And on a separate issue, what accounts for the delay in the octane plant upgrade? Is it cost? Is it a function of the market and does that change the perspective economics of the upgrade?
Well, our earlier date was that we hoped to get that plant converted by June. Now it’s September. The additional delay was we thought we ought to take another 60 days or so and study the alternate processes that we’ve got, running some pilot plant activities. It will take approximately a month to get the data from those pilot plant activities. So we just float it down to make sure when we do start the plant up, we start it up and feel confident that it will perform the way we expect it to. The other part of the equation here is that we’ll have approximately 12 to 14,000 barrels per day of iso-octane. We’re working on the marketing of that. Expect to have that concluded and in place before September.
The other thing that’s going on that improves the economics a little bit in the interim is we will be selling isobutylene. Industry demand is such that you can’t incrementally make margins on MTBE. We will run the plant to produce some quantities of isobutylene for an isobutylene customer here on the Gulf Coast. We have an alternate use but it’s not a full-time alternate use.
So we do expect to sell some MTBE. Right now, the MTBE margin is positive. We are in the process of starting that plant up as we speak, and we expect to be in production during February, producing a combination of isobutylene and MTBE for the industry.
Okay. And in terms of the costs of the upgrade, is that comparable from where it was before?
I would add approximately 2 to $3 million more to that than we previously indicated it would be in the $20 to $25 million range. We’re still looking at probably being in the $23 to $27 million dollar range.
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Okay, great. Thank you very much.
And that’s for 100% of the capacity. Obviously, we have a one-third part in that activity.
Thank you.
Thank you. Our next question comes from Eric Olson of Sanders Morris Harris.
Yes, good morning. On the rating agency question, I’m just curious what their initial concerns are in your initial discussions with them and how you plan to address those concerns? And on your overall leverage number, which you gave as I believe 4.57 times, is there a long-term goal to get that, say, below four?
Taking your last question first, yes. There is a plan to get it below four. We certainly feel comfortable with it being closer to 3 1/2, but our goal is to keep it in the 3 1/2 to 4 times range.
With respect to the concerns of the rating agencies, again, we’ve not had the opportunity to sit down and go through in great detail the plans for the merger and the financial structure, although we do plan to do that with one of the agencies here in the next couple of weeks, and I would guess that we would do the second agency not long after that. I think the obvious concern that you’re going to have is not necessarily with the financial ratios that we’ve modeled but more on execution, similar to the Mid-America transaction where we had considerable leverage. We think that we will be able to demonstrate that. Obviously with the Mid-America transaction, we were able to execute our refinancing plan and we did it faster than we had told them we would.
I think in this transaction, we’re in a different situation in that the equity markets were more favorable than they were a year, year and a half ago. I think we have a conservative plan with respect to refinancing. That includes not only issuing equity but also refinancing their high coupon debt. We think there are significant benefits there as well. Once we sit down with the rating agencies, we’ll be able to understand the additional concerns they have and address them specifically.
Are you targeting any additional asset sales here in the de-leveraging process to pay down debt instead of issuing equity?
No. The assets that are involved in this merger, we think are all very attractive. The FTC may decide that we need to dispose of some assets. We think any assets that would be required to be disposed of would be relatively small.
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Thank you.
And it should be pointed out, too, that through the DRIP program, we are buying equity on a quarterly basis. In the month of December we purchased $100 million of equity. So we are working even though we haven’t done our first public offing yet, we are working on getting that ratio down.
I’ll tell you basically, Eric, this is Dan. The high point of our debt to total capital is at the highest level it would be and it would not go up as we go forward. I mean, we structured the GulfTerra deal on the two-phase ideal on purpose just because of this reason. We wanted to do a two-phase deal where we wouldn’t get the high leverage like we did with the Williams Mid-America Seminole deal.
Also, at the same token with the DRIP program, the amount of Enterprise buying is put into equity every quarter rather than the $100 million of Series B that we put in Mid-December when we closed the deal. Through the DRIP, we are going to do another $30 million give or take something for every quarter through the first quarter of 2005. The only difference in that is under the first quarter, which is in the February deal, since we put in $100 million in December we will only put in $20 million of the company’s money back into that program. After that, it will go back up to $30 million a quarter. So the high point of this deal is where we are today, not only the debt to EBITDA but the debt to total equity would go down from where we are today.
And just to kind of review that. In December, Dan had planned to purchase $90 million of class B units and he also bought $30 million of equity through our DRIP program. He decided to increase the amount of Series B to $100 million and decrease the purchase under the DRIP plan in the first quarter of ‘04 by $10 million or so, getting that 10 million of equity in a little faster.
Great. Thank you.
Thank you. Our next question comes from Ron Londe of A.G. Edwards.
Yes, I’m curious. Over the years, you’ve had a terrific relationship with Shell and always emphasized the improved and higher gas production that you expected to come out of the Gulf of Mexico with regard to the Shell assets. Recently, Shell has revised downward their reserve estimates. I was wondering how that’s going to affect you in the future. You know, probably not much short term but maybe a long-term perception of where gas is coming from?
We don’t. As you probably know, the reserves adjustments were for Australia and Nigeria primarily. What they are trying to do, if I understand it right, is they don’t put it in an approved category until it is flowing in production, or they have a customer on the other end buying it, and then they put it into the approved category. Most of what we’re looking at is in the approved category and has been moving. The new additions that they’re bringing in this year is Na Kika, which is a substantial discovery of a lot of small discoveries being gathered up in one big platform here of tie-backs and most of that — some of that volume’s even third party volumes.
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No, we don’t expect the Shell volumes to be involved in that reevaluation at all, and we still see that Shell is continuing to progress on their Gulf leases and drilling and then planning to add more. It appears that a lot of their volumes, as you probably know, when we start talking about BP volumes, Shell is involved in a lot of those BP discoveries so we’ll be getting Shell gas, as well as the BP gas. The BP gas comes under long-term contract with the Shell gas being dedicated to our process in the downstream assets. So no, we don’t see that as being a negative at all. As a matter of fact, we’re still very enthused, and as you said, we’re still working very closely with Shell on the developments in the Gulf of Mexico.
But you don’t see any change in their development plans over the near term?
No. We don’t.
But I think on the idea with GulfTerra, GulfTerra has onshore assets that more fits South Texas and the Texas Gulf Coast than the original Shell assets that fit us in Louisiana and Louisiana Gulf Coast and Mississippi Gulf Coast. So with the combination of us and GulfTerra now, we’re in a stronger relationship with Shell to do more for Shell because I think the Great White is probably going to come into the Texas Gulf Coast rather than to Louisiana Gulf Coast. They haven’t had a decision on what they’re going to do with that, but just from the location of it, it’s more than likely it will come into the Texas Gulf Coast versus the Louisiana Gulf Coast. I think from my relationship with Shell, we’re stronger now than we were before.
Okay. Thank you.
Thank you. Our next question comes from David LaBonte of Smith Barney.
Good morning, guys. Dub, or perhaps Jim, could you talk a little bit more about the process environment in south Wyoming and how that’s translating into increased throughput on Mid-America and Seminole? I know that you said that the profit margin has crept into positive territory. The second question, regarding your new tariff structure on Mid-America and Seminole, how is that increased volumes in margin in the recent quarter versus an improvement to just general business environment overall?
Let me start off, David. I’ll let Jim also add to the explanation. We have seen extremely strong margins in January. I think we saw margins get as high as 6 to 8 cents positive in the Wyoming area and the Opal and Rocky Mountain Plants. The margin has since decreased a little bit, but it’s still in the positive category where we haven’t had to trigger our incentive program so far in the month of February, but if so, the way that works is quite simple. Just on a daily basis we lower the tariff to give the processors some incremental margin that is better than putting the ethane back in the gas or leaving the ethane back in the gas. Primarily that gas is going to California. So we’ve seen about an 80-cent margin between the price of gas in that area going in the Rocky Mountains going to primarily to California and versus the Henry Hub. So it’s been a very positive situation. I think what lead to that is the strong petrochemical demand. It isn’t just the gas spread. It is the ethane price in the Gulf Coast. So, with strong demands for ethane in the Gulf Coast, that’s what leads you to good processing margin not only all along the Gulf Coast but also in the Rocky Mountains.
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I don’t know if you’ve been watching ethane values. That gets back to the processing margin here in the Gulf. We indicated in the review here that we have seen it go from 4 cents to 17 cents as far as the Gulf Coast processing trend. That’s due primarily to ethane values increasing. And in the whole hydrocarbon area, ethane’s not the only one that increased, propane and butane and natural gasoline also increased to get those margins back into a healthy range.
Now, volumes on Seminole and Mid-America, they’ve basically just stabilized at 700,000 barrels a day? Since Jim deals with that every day, I’ll let him comment on the volumes going through the systems.
David, what we saw in the fourth quarter versus the third quarter was 850,000 barrels a day up from 800. We saw a 50,000-barrel a day increase across the whole system.
Okay. And again, could you or have you done kind of a breakout to see how much of an increase was attributed to the general business environment versus your new tariff structure?
Well, we saw most of the increase while we had extremely high positive margins in the Rockies. Now if we start seeing a negative position here in February and beyond, we’ll obviously be working with the processors to maintain that volume through this incentive tariff. We don’t expect to let that volume go down if the margins allow us to get the incentive tariff and keep the volume flowing. That’s our plan. We’re going to use the incentive tariff to keep the maximum volume in the system.
All right, guys. Thanks.
Thank you. Our next question comes from Dennis Coleman of Banc of America Securities.
Hi. Good morning. Maybe just one more shot at this incentive tariff. Did you, when you were setting this up, did you do a back cast to see how — what impact this might have had on volumes or earnings in the second and third quarter of last year that we might kind of compare it with?
I think the answer to the question is no, we didn’t do a lot of calculations in the past. What we’ve done is seen a severe reduction of our margins within that pipeline system and we think we can keep the volumes up in any environment and if the environment is such that we have to use the incentive tariff, we’ll still be making a lot of incremental margins on those volumes and intend to maintain them as high as possible trying to keep the system running close to maximum operating rates. This incentive tariff that we talked about, it’s in the first tariff so it is a public record of what the tariff is based on. If you take basically the cost of moving product on to the Gulf Coast and you take the costs of moving product from Louisiana up the Gulf Coast, the Gulf Coast of Texas more than the Gulf Coast of Louisiana, it’s not much more than the Gulf Coast of Louisiana.
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This incentive happened based on the basic differential of each basin, like the differential of gas versus Henry Hub, and watching the Wahoo Junction, San Juan Basin. Each basin out there that sells gas is where this incentive tariff comes in to play. We use the tariff from that area from Belvieu versus tariff from all over Texas to Belvieu. In that basis differential in the range of 50 to 65 cents an MCF difference between Opal and Henry Hub. Then that means any time it gets below that, you start on the incentive tariff. If the basis differential of gas, which is a gas data deal that we operate off, if it’s in the 75 to 85 cents differential on gas, then the incentive tariff doesn’t come into place.
So it’s strictly based on what the gas basis for that particular flat location is, and each plant out there has a basis that is published every day. It is based on that gas price versus Henry Hub gas price and the difference in pipeline tariffs. That’s how you get to the incentive tariffs. If you go back before it was put in, there was a blowout differential of $1.50 to $2 most of the time. After Kern River came in, for a short period of time, it was in the 30 — 40 to 50 cents on gas I’m talking about.
Right.
The formula is based on gas differential of that particular gas plant versus Henry hub. That means the economics could bring it to the Gulf Coast. The plant economics works just as good in Wyoming as it does in the south. It’s all based on what gas price is and what that particular basis is.
Okay. That helps.
Let me confuse you maybe a little further. What the ethane value is at Mont Belvieu. Because the ethane value at Mont Belvieu sometimes fluctuates to a different drummer than the BTU value of gas. Sometimes it’s quite tight with the BTU value gas and sometimes it’s much larger. So it also relates to the value of ethane at Mont Belvieu, which has, as we said earlier, is completely dependent upon good demand out of the petrochemical industry. That is one of the major culprits of the second and third quarter, lack of volumes for the Rocky Mountains and the depressed ethane price and lack of demand from the petrochemical industry.
Right. Okay. On a different line, for the El Paso plants that you’re having audited right now, just in terms of getting an EBITDA estimate for them just a broad cup, eight times earnings, is that a decent ballpark of where we should think about those plants being?
No. That’s much too high. These are gas processing plants and pretty stable in their operations since they’re integrated into pipelines and fractionation facilities in south Texas. The EBITDA that we expect to get out of that $150 million dollar investment is in the range of $25 to $30 million so it is a five to six times EBITDA number.
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Okay.
Also, the problem --
Just one last one if I can. The debt refinancing, you’ve made it clear that you’ll keep the GulfTerra debt at GulfTerra but when it’s refinanced you’ll reissue out of the GulfTerra entity, is that correct?
No, the plan is to refinance all of that debt and to have all of our financing at the OLP level. There will continue to be financing at the project entities, but the majority will be at our OLP.
Okay. Okay. Thank you.
Once again, if you would like to ask a question, that is star one on your telephone touch pad and star two to cancel. We have a question from Brian Watson of RBC Capital Markets.
Yeah, on the sustaining capital expenditures, you have future plans for these pipeline integrity costs or do you think you’ll see any Cap Ex more in the $3.5 million range without those costs?
You’re asking what we expect the pipeline integrity costs to be for 2004?
Right. I guess for the fourth quarter you said you had $2.3 million of the pipeline integrity costs. If you back those out it would have been $3.5 million about. So do you expect more of the sustaining or more of the integrity costs or are you done with those?
No, we’re not done. We’ll continue this year.
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As a rule that we’re operating under, you have to have 50% of your systems done by November, I believe, of this year, and we’re working towards getting that accomplished. We’re pretty close to having that accomplished at the present time. We are trying to stay ahead of that. But we’re expecting, I think, in the range of $15 to $19 million on an annual basis.
Yeah, for the full year.
The full year.
Okay, thanks.
Thank you. Our next question comes from Gil Alexander of Darphil Associates.
Good morning. Could you give us your first cut on what you see as your cash flow range for the first quarter of this year?
We’ve not given any guidance with respect to the 2004 and frankly not prepared to do that.
Could you just recap for us where you see business improving in this first quarter?
I think having January behind us, we’ve seen a much stronger ethane market as we’ve seen earlier and good volumes through our processing facilities and our fractionators and all the way through the value chain. So we feel like we’re off to a good start in January. The operating rate of the ethylene plants is currently in the range of 86%. All of the information we get from our customers is they’re planning to move that on up into the 87, 88% of capacity, which looking at the balance of the feedstocks that they use, that means they will have to use more ethane and propane to bring those volumes up so we’re expecting a strong demand for the petrochemical industry during the first and second quarters. No question about that. Beyond that, I think we obviously are just not in a position to give any guidance on the first quarter at this time.
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Thank you.
The forecast is, correct me if I’m wrong, I think the run rate is around 54 billion pounds per year of ethylene in the fourth quarter. And this is what all of the consultants are coming up with that. So when you see that type of a number, basically all of that increase would be in the light end deals, the heavy ones are still operating pretty well at capacity. So the light end deal would be the one that takes the 2 to 3 billion pounds a day up on the deal. So from that standpoint, we still a lot are a lot stronger market than we were in 2003. I think the low rate of 2003 was in the 28% to 29% range.
Let me give another encouraging comment to why we feel a little bit of bullishness in the year 2004. We’re seeing a lot of these heavy crackers that we have on the Gulf Coast are internationally fed. They get condensate from Nigeria, they get napthas from different places around the world. There is a strong, strong demand for napthas in the Far East and condensate in the Far East and it’s structurally changing the heavy crackers in the Gulf Coast. They’re having a difficult time both price and volume of getting their feedstocks satisfied. From that standpoint, we also expect to see more ethane and propane being used in the Gulf Coast.
I thank you very much.
Again, if you have a question or a comment, that is star one on your telephone touchpad. We have a question from John Tysseland of Raymond James.
Hi, guys. Good morning.
Good morning, John.
Looking at your octane enhancement business over the next year, until you have that conversion completed, where do you think that business goes from now until September, or I guess more on run rate. Have you seen it improve from this quarter or do you think it’s just going to continue along where it currently is operating?
You know, even under best conditions MTBE was a little seasonal. And the season was always the weakest in December and January. And it’s pretty much where the industry took its turn around, which was usually a month or so long. But what we’re expecting is that some spring gasoline may start moving normal butane out of gasoline because of its vapor pressure limitations, we’ll have a stronger demand for MTBE to enhance the octanes in refined gasoline and so we think we’ll have reasonably good demand in the second quarter.
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Now, if you ask me to estimate what the price will be, I can’t do that at the present time. But I think with the shut down facilities that we’ve seen and I think they’re permanent, Global Octanes and Texas PetroChem, EOTT and that plant was bought by Valero. All of those MTBE plants were probably not going to start back up on a one-time basis. They haven’t spent the money to have their plants in an environmental sound position and maintained properly. So I don’t see those operating. I think we’ll probably have a good, fairly good second quarter MTBE demand. Meantime, we’re marketing in February. We’re not real enthused about the price but we probably got about a 5 to 7 cent margin at the present time.
John, if you look at the numbers, if you take California out, California’s always been done with imports. California has no effect on the Gulf Coast MTBE market. So once you take them out of the Gulf Coast MTBE market it’s really New York or the Northeastern States. Not only New York but all of the Northeastern States will be taken out. That is not the big volume of MTBE that goes into that market. There’s been a shutdown of probably 50,000 a day of MTBE and 50 to 60,000 a day but you only have actual loss in demand probably 20 to 25,000 a day of actual shut down demand. So the rest of the Southeast and the South that will probably still use MTBE for a limited number of years.
So the economics of this year could be just on the volume that it was last year. And really, you get into it if the motor gasoline is tight this summer, especially high octane, it will go into the motor gasoline. You’ll have a strong MTBE market for a couple of years until you come out with an outlet that takes care of the octanes of the motor gasolines.
So we don’t expect this summer to be a weak MTBE market. We take it to be a strong MTBE market only because of motor gasoline demand.
Excellent. My other question was on your maintenance Cap Ex number. I guess it sequentially came down. If you look next year or over the next couple quarters, do you have think it’s going to look more like the September quarter or December quarter?
John, in the quarter ending in September, one of the things you had in there was the reroute of a section of pipe on the Mid- America and Seminole system for that reservoir. We finished that reroute in the fourth quarter, so I think probably a run rate on sustaining Cap Ex is probably going to be more at about prior to looking at anything with the GulfTerra just Enterprise stand alone probably more in the $15 to $16 million range.
Thanks, guys.
Again that is star one if you have a question or comment.
Miss operator, I think we probably can take any other questions off line. If you’d go ahead and give the replay information.
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Thank you. If you should need to listen to the instant replay of the conference, the telephone number is 1-800-282-5736. Again, the replay for today’s conference number is 1-800-282-5736. Thank you.
Thank you.
Thank you, everyone, for participating in today’s teleconference and have a great day.
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