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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934

Date of Report: November 22, 2004
Date of Earliest Event Reported: November 18, 2004

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation)		1-11727 (Commission File Number)		73-1493906 (IRS Employer Identification No.)

2838 Woodside Street
Dallas, Texas 75204
(Address of principal executive offices) (Zip Code)

(918) 492-7272
(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS


Item 2.02. Results of Operations and Financial Condition
Item 9.01. Financial Statements and Exhibits
SIGNATURES
EXHIBIT INDEX
Transcript of Earnings Conference Call

Item 2.02. Results of Operations and Financial Condition.

Energy Transfer Partners, L.P. (the “Partnership”) held a conference call on November 18, 2004, to discuss its financial results for the fourth quarter and fiscal year ended August 31, 2004. The Partnership also answered questions from participants during the call. A copy of the transcript of the conference call is attached to this report as Exhibit 99.1 and is incorporated herein by reference.

Item 9.01. Financial Statements and Exhibits.

(c)		Exhibits. The following exhibits are being furnished herewith:

		Exhibit Number 99.1 – Transcript of earnings conference call on November 18, 2004, discussing financial results for the fourth quarter and fiscal year ended August 31, 2004.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	Energy Transfer Partners, L.P.

	By:	U.S. Propane L.P., General Partner
	By:	U.S. Propane L.L.C., General Partner

Date: November 22, 2004	By:	/s/ Ray C. Davis
		Ray C. Davis
		Co-Chief Executive Officer and officer duly
		authorized to sign on behalf of the registrant

	By:	/s/ Ray C. Davis
		Kelcy L. Warren
		Co-Chief Executive Officer and officer duly
		authorized to sign on behalf of the registrant

EXHIBIT INDEX


Exhibit No.		Description
99.1		Transcript of earnings conference call on November 18, 2004, discussing financial results for the fourth quarter and fiscal year ended August 31, 2004.

exv99w1

Exhibit 99.1

HERITAGE PROPANE

November 18, 2004
2:00 p.m. CST


Moderator		Welcome to the Energy Transfer Partners call. At this time, all the participant lines are in a listen-only mode. However, there will be an opportunity for questions. As a reminder, today’s call is being recorded. I would now like to turn the conference over to Mr. Ray Davis. Please go ahead, sir.

R. Davis		Thank you, everyone, for joining our quarterly earnings call. I thought we would start out today on the phone with us today we have myself and Kelcy Warren, Mike Krimbill, and John Daigh, who is our Treasurer is going to help us through the call.

		We’ve had a very busy year, as I think all of you know, but just sort of an overview. Since January when we did the reverse merger with Heritage, it created some strange accounting anomalies to the reverse merger accounting. Also, we changed the fiscal year of Energy Transfer at that time to match what was Heritage’s fiscal year. When you go back to September ‘02 to pick up the first month of the year, there wasn’t an


		Energy Transfer in that month, so in some cases, we’re comparing 11 months versus 12 months.

		Also, the reverse merger accounting required the Energy Transfer financials to be the ongoing financials, which created some other anomalies. If you all will bear with us through this next year, this will all level out and the following subsequent years will be a lot easier to follow.

		In conjunction with the merger, we did an equity offering of $350 million at that time to close the transaction. Then in June, we did the Tufco acquisition from TXU for $500 million and had a net proceeds of $194 million. Also in June, we started up our Bossier line, which is our new 36-inch pipeline extension. It’s about a Bcf of potential capacity, about 78 miles. The total cost on that was about $71 million, and it was paid for through internally generated funds.

		On November 1^st, we closed some of the midstream assets from Devon and the Austin Chalk. Those cash flows will start showing up in our financials, starting in November, and that acquisition was $64 million. Also, for the fiscal year ‘05 on the propane side, we did approximately ten acquisitions for a total of $58 million in acquisition price.

		With that, I’ll turn it over to Mike Krimbill to go over some of our financials.


M. Krimbill		Thanks, Ray. As Ray said, the historical numbers do not reflect, both the propane and midstream results for a full 12 months, so we are going to focus on what is called the aggregate numbers. Those have in ‘04, both the propane and midstream for 12 months and in ‘03, it has the propane for 12 and the midstream for 11. It’s as close as we can get to apples and apples.

		In those two periods, we had net income in fiscal ‘04 of $121 million, versus $77.8 million for the prior year. EBITDA was $250 million for the current fiscal year and $188 million for ‘03, which is about a 33% increase. Both the net income and EBITDA for the current ‘04 fiscal year were reduced by about a little over $4 million of merger expenses, which would be non-recurring.

		With respect to distribution, as you probably know, in the last 12 months, we have raised the distribution from $2.60 to the current $3.30, which is about 27% increase. The unit price at the end of fiscal ‘03 was $31. In August ‘04, it was $43, and today, I believe it’s in excess of $51.

		With respect to our distribution coverage, we provided earlier guidance that our projected ‘05 EBITDA would be $340 million. At that level, we anticipated our distribution coverage at $3.30 to be about 1.48 times.


		Rather than going through a bunch more numbers and percentages, what we’d like to do is open up to questions and answers, what you have on your mind specifically.

Moderator		From the line of Ron Londe with A.G. Edwards. Please go ahead.

R. Londe		Thanks. Maybe just start off talking about the propane business a little bit. Mike, can you give us an idea of where you are relative to your budgets, and what you see in the marketplace right now from the standpoint of competition and being able to pass higher propane costs along to customers? It looked like for 2004 fiscal year, that you were on a volume basis about 5.6% higher than you were the year before. Maybe you can give us a feel for what you’re looking for next year.

M. Krimbill		You are correct. The ‘04 results, again, this is on the aggregate basis, we were about 5.67% over the prior year volumes. The volumes were from acquisitions. It was about 6.5% warmer than normal, but it was 2.7% warmer than the prior year.

		I want to talk about margins. There was no margin decline. Margins were steady. Our mix was a little different. The increase in volumes over the prior year was due to the lower margin industrial, agricultural, commercial gallons rather than having additional residential.


		With respect to ‘05, we’re entering an era that we’ve never been in before with very high propane prices for an extended period of time. We’ve seen prices $0.90 to $1.20 for a month or a couple of weeks. We’ve never seen it for several months in a row.

		The key is maintaining margins and exceeding budgeted margins because we know we’re probably going to exceed budgeted costs for fuel to run the bobtailed service trucks. We have thus far in ‘05 seen our margins either maintained or been slightly increased. We’re not seeing any kind of margin decline, even though we really haven’t had any cold weather.

		Right now in the weather, it’s been, for the most part, warmer than normal. Although, the weather forecasts are for colder weather in December and January, so we’re not ready to throw the towel in yet on a significantly warmer than normal winter.

		Was there anything else, Ron, that I didn’t address?

R. Londe		It was pretty good. On the Energy Transfer side or the gas side, can you give us an idea of where you are from the standpoint of midstream gas volumes and transportation volumes?

M. Krimbill		I can give you what we have, where we were through the end of August, Ron. If I compare fourth quarter of ‘04 to fourth quarter ‘03, our volumes


		were up about 14% on the midstream side and something over 250% on the transportation side. The reason for that is, we have Bossier coming on in late June and building through July and August, and we have the Tufco acquisition coming on during that period of time on the transportation side.

		If I compare fourth quarter with third quarter, on the midstream side, we’re up about 21% and on the transportation side about 120%. Again, that volume is building and also ... has done extremely well.

R. Londe		From the standpoint of bypassing your gas plant, what has been your experience in the last couple of months?

M. Krimbill		The last couple of months the frac spreads have been very good up until this month, and we’ve been in full recovery.

R. Londe		This month, can you give us an idea for the trends? How many days are you bypassing versus fracing?

M. Krimbill		The frac spreads are down in November. I don’t have in front of me, the number of days that we bypassed. As you know, we can go into different modes. We can first go into ... rejection and then, we can go into the full bypass, so it could be a combination depending on where the frac spreads are compared to the first of the month pricing.


R. Londe		Thanks.

Moderator		Our next question is from the line of Yues Siegel with Wachovia Securities. Please go ahead.

Y. Siegel		Thanks. A couple of questions, Mike or John, can you help me to understand the magnitude of the unrealized gains on derivatives and how we should be thinking about it going forward?

M. Krimbill		The unrealized portion?

Y. Siegel		Yes.

M. Krimbill		I want to take this opportunity to explain to the community this item on our income statement because it could be misleading to an initial reader of our statements. I’d, first of all, like to say that it’s our company policy to not speculate on pricing and we enforce that vigorously. On our income statement ,you’ll see about $25 million of derivative gains, in this case. What that amounts to really is repeatable margin. I can break this down into three different categories and it’s all risk management activities relating to hedging our business.

		The three categories I’ll talk about are Nimex activities, basis activities, and gas daily activities. Of the $25 million, about $6 million of it relates to NI mix activities. Part of our producer services activities is we’ll get


		customers and/or suppliers that will come to us and want to do a fixed price deal. Maybe it’s in our Elk City plant; maybe it’s in Texas some place. They’ll desire to either sell on a fixed price or buy on a fixed price and we’ll accommodate those customers. But consistent with our policy of not speculating, we’re not going to take a naked position on that. We’re going to go and hedge it. One of the ways that we’d hedge that is enter into Nimex transactions to cover any potential movement in price.

		Those that are familiar with this market know that the Nimex contract only gets you back to the Henry Hub, which is a location in Louisiana. If you have a transaction, for example, at our Oklahoma facility and if you only entered into a Nimex transaction, you would have exposure for any differential movement between Oklahoma and Louisiana. We cover that with a basis transaction.

		You may have one physical, for example, sale at a fixed price that you need to cover with a Nimex transaction that gets you back to Louisiana and a basis transaction that gets you from Louisiana back up into Oklahoma. That covers the Nimex activity and part of the basis activity.

		Of the total $25 million, about $9.9 million relates to basis activity. I spoke of the one area that we use those basis transactions, and that is to get back to a more localized market center. The other thing that we do is we protect our margins on our Oasis pipeline. Where if we go out and look at


		basis differentials in the long-term relating to the price of the gas as the west end of Texas, or the Waha Hub, compared to the east end of Texas, the Katy Hub, where our pipeline connects and we see a wide margin, we will enter into basis transactions which in effect locks in our gross margins and our cash flows for our Oasis assets. Those are the two ways that we use basis transactions.

		The third area is gas dailies and that is the remaining $10 million of the $25 million. As a processor, we are naturally long the first of the month index price. As you probably know, we purchase most of our gas behind the plants, based on the first of the month index price, but we don’t necessarily sell 100% of our gas on the other side of our plant, based on the first of the month index price. We sell some of it, but not all of it.

		Rather than being naked and exposed on the price change from the first of the month compared to the average price for the month, we will enter into what is called gas daily transactions, which really trade the average price for the month back to the first of the month price. In effect, it matches us back as close we can get to the purchase economics of first of the month pricing, compared to the sales economics of first of the month pricing. All of that combined reflects about $25 million of derivative gains on our income statement, which really should be viewed as a part of gross margin because that is in effect what it’s hedging.


Y. Siegel		From a cash flow perspective, is that going to match, number one? Number two, how should we think about it going forward in terms of the magnitude? How predictable is that, or forecastable, from our vantage point?

M. Krimbill		There are two questions there. From a cash flow perspective, of the $25.8 million that’s reflected on our income statement $2.9 million of it is unrealized, so basically, $23 million of it is already cash in the door. In terms of repeatability, it is absolutely repeatable because you’re going to see that margin either in this line or in the gross margin of our assets, one or the other. It’s just a matter of protecting our inherent risks that we have.

Y. Siegel		I’ll shift gears. I appreciate the answer. Can you guys give us an update on where you are on some of the internal growth objectives that you went over few weeks back at the Allis meeting? Is there any update at this juncture in time?

M. Krimbill		Kelcy, do you want to handle that?

K. Warren		Yes. Eve, the Barnett Shell project that we’re very proud of, as you know, has really exceeded our expectations in the way of volume commitments. We are ahead of schedule of we stated to you back in Cherokee, Texas a month or so ago, in fact, way ahead of schedule in volume commitment.


		Construction schedule on that pipeline, I would say we’re about on schedule. There will be several condemnations. It’s inevitable. We’ve tried to avoid that, but it’s just impossible. As you know, that is a very populated area where we’re building this pipeline, and it’s very difficult to acquire right of ways. We still expect that the total project will be complete by the end of the first quarter of ‘05. Phase one of this project will be complete probably within the next month and then another phase laying up to Highway 377 will be the next phase that will be completed as well.

		That project, I just can’t say enough good things about it. In fact, in hindsight, I wish we had built a 30-inch pipe instead of 24, but we made the best decision we could at the time.

		The Bossier project is also ahead of schedule in the way of deliverabilities. We’re very pleased with the volumes we’re seeing. Eve, as you know, XGO was behind schedule on completing their treatment plants. They now have those plants operating and they’re operating very well. I would say our volume is growing every month, so that has been very positive.

		Other projects that we talked to you about were the expansion of compression at Bethel. Ray and I have approved the AFE to order those compressors and that project will move forward. Naturally, it will increase the terms on the Bethel Sawbones storage facility in the near future.


		The other project, the line from Olathe to the Bethel storage facility, has still not been approved by the board. In fact, it’s not been brought to the board. We’re still negotiating transportation agreements with producers, and we’re very optimistic that we will get there to the finish line, but we’re not ready to state that that project is for sure at this point.

		What else, Ray? What did I miss?

R. Davis		The only thing that I would add, Kelcy, Eve, just a point of clarification. When Kelcy is talking first quarter ‘05, he is talking calendar year, not our fiscal year.

Y. Siegel		Do you have what the current volume is it on the Bossier pipeline?

R. Davis		We’re a little under 400 million and growing. The only other thing you might mention, Kelcy, is our new 16-inch line and the treating plant we’re moving.

K. Warren		Thank you, Ray. Eve, we’ve had a little bit of a pleasant surprise just occurred. We’re bound by confidentiality agreements, so I’ll speak a little cryptically here. There is an area called the Deep Bossier that the producers have known that this could be productive, but nobody had quite figured it out. Some of the producers are, in fact, finding the science that


		makes that work. We’ve entered into a long-term contract with the producer, whereby they’re paying demand fees to reserve capacity. Whenever a producer does that that makes a clear statement when they’re stepping up to pay $0.10 on 100 million a day, let’s say, for example, whether they use the capacity or not. That’s a real statement of confidence.

		As part of that, we were obligated to lay 16 miles or so of 16-inch pipe, which is under construction now, and to move one of our ... treatment plants directly to the location. We are in the process of doing that. That project is going quite well. We’re not experiencing the right of way problems there that we are on the Barnett Shell, so I expect that project to move forward quickly.

Y. Siegel		Do you guys have an updated capex budget for ‘05?

M. Krimbill		No, I don’t have it in front of me.

Y. Siegel		It sounds like you’re keeping busy.

R. Davis		Obviously, the treating plant that Kelcy just mentioned is a new project even since our analyst meeting. It was kind of a windfall for us and we’re excited about what is happening there.

Y. Siegel		Did you say what capex was required for that?


R. Davis		The treating plant is 150 million a day treating plant. Kelcy, do you remember the capex number? It’s all growth capital, Eve, which would be separated from our maintenance capital.

K. Warren		Ray, I think it’s approximately $10 million, but Eve, we’ll get you an exact number.

Y. Siegel		Is the intent still to try to finance the growth with the excess coverage on the distribution?

R. Davis		That is correct and also, that coupled with our revolver.

Y. Siegel		Thank you.

Moderator		Our next question is from the line of Jim Long with AmeriGas. Please go ahead.

J. Long		Could you talk about capital spending for fiscal ‘04?

M. Krimbill		For the entire MLP?

J. Long		For actually just ETP, please.


R. Davis		We do not have that number in front of us.

Moderator		The line of Mark Easterbrook with RVC Capital Markets. Please go ahead.

M. Easterbrook		Just quickly, what are the volumes on the Bossier pipeline now?

R. Davis		That is what I was just mentioning a minute ago, Mark. There is a little less than 400 million and growing every month.

M. Easterbrook		The capacity on that is still 500 million, but then it can go up to a Bcf with compression adds?

R. Davis		That is correct.

M. Easterbrook		Secondly, obviously, with the coverage being 1.48 for ‘05, that excess cash flow, is that going to be used mainly for growth capex, or are you guys planning to reduce some debt with that?

M. Krimbill		Yes and yes.

M. Easterbrook		Thanks.

Moderator		From the line of John Ticeland with Raymond James. Please go ahead.


J. Ticeland		It sounds like activity in Texas is remaining pretty strong. Could you just touch on what you’re seeing up in Oklahoma in those midstream assets?

R. Davis		We’re seeing increasing volumes, however, there have been a couple of wells that have been a little disappointing, as opposed to the initial discovery well up there at the Buffalo Creek well. There is still an awful lot of drilling activity and our volumes are continuing to grow. They all aren’t going to be 40 million a day wells, unfortunately, but even at 20 million a day, they are awfully good. I think we’re running total system up there, if you wouldn’t hold me to the number, of about 265 million a day going through our system in Oklahoma.

J. Ticeland		Is there any, do you think, growth capex you can spend up in Oklahoma or is that just a little bit down the road?

R. Davis		Kelcy, do you want to handle that?

K. Warren		Yes. John, that is an excellent question. We need to probably look at acquiring some assets that would be complementary to our system. I think the growth capex is going to come in the way of well connects and we’ll be very active in that area, but there are some things we could do to make that a more profitable endeavor for us. There are strategic type acquisitions that I would like to see us pursue.


J. Ticeland		Last question, if you look at your Texas assets, you have a big system down there that is pretty well connect. Are you still pretty comfortable in going after the higher margin business from the producers and at this time not really too interested in the demand side more fee-based businesses?

K. Warren		No. In fact, let me take the opposite side of that. Major mistakes a lot of pipeline companies do is, they will build a pipeline project to address a capacity constrained area and their very actions cause their own failure. What I mean by that is, they will increase the capacity and crater the margins. A way to avoid that is discipline and that is to very carefully and in a very disciplined manner negotiate demand components of all your contracts.

		If a producer desires to move gas through you system, he must pay a demand component and then a small commodity component. I’m very, very proud of our people and can’t say enough good things about the job they’ve done as it relates to that. John, really the majority of our business is in fact fee-based demand charge commodity component type structure.

J. Ticeland		I kind of meant the opposite side of it, not necessarily with the producers, but from municipalities or utilities or electric generation plants. Are you hooking up, for instance, anything off of Oasis or any other lines?

K. Warren		You mean in the way of markets?


J. Ticeland		Yes.

K. Warren		No. Actually, we have five power plants connected somewhere off the Oasis system and/or the 30-inch. Of course, our largest hauler is in fact THU Generating Company, so we have many power plants connected through them, but I am not aware of any new markets that we’re connecting to our system right now. Are you, Ray?

R. Davis		No.

J. Ticeland		Thanks, guys.

Moderator		To the presenters on the call, no further questions in queue.

R. Davis		Ladies and gentlemen, we thank you for your time and we hope this has been informative. We plan on doing it every quarter. As always, if any of you have any questions you would like answers for, please feel free to call us. Thank you very much.

Moderator		Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation.

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