Genesis Energy LP (GEL) 2011 Q3 法說會逐字稿

Welcome to the 2011 third-quarter conference call for Genesis Energy. Genesis has three business segments. The Pipeline Transportation division is engaged in the pipeline transportation of crude oil and carbon dioxide. The Refinery Services division primarily processes sour gas streams to remove sulfur at refining operations principally located in Texas, Louisiana, and Arkansas. The Supply and Logistics division is engaged in the transportation, blending, storage, and supply of energy products including crude oil, refined products, and CO2. Genesis' operations are primarily located in Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, and the Gulf of Mexico.

During this conference call, management may be making forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. The law provides Safe Harbor protection to encourage companies to provide forward-looking information. Genesis intends to avail itself of those Safe Harbor provisions and directs you to its most recently filed and future filings with the Securities and Exchange Commission.

We also encourage you to visit our website at GenesisEnergy.com where a copy of the press release we issued today is located. The press release also presents a reconciliation of such non-GAAP financial measures to the most comparable GAAP financial measures.

At this time I would like to introduce Grant Sims, CEO of Genesis Energy, LP. Mr. Sims will be joined by Steve Nathanson, President and COO; Bob Deere, Chief Financial Officer; and Karen Pape, Chief Accounting Officer.

Thank you and welcome to everyone. This was a busy quarter. Not only did we report record quarterly earnings and distributable cash, but we also successfully completed two financing transactions and we closed on the acquisition of additional assets to expand our black oil service capabilities.

The Partnership's performance will allow us to make a distribution later this month of $0.4275 per unit, a 10.3% increase over the year-earlier quarter. This represents the 25th consecutive quarter in which we have increased the distribution to our unitholders and the 20th quarter during such period the distribution has been increased by at least 10% over the year-earlier quarter.

We are pleased with the continuing and increasingly integrated performance of our existing businesses. We are excited about several of our growth initiatives.

Last week we announced the execution of agreements to acquire interest in several crude oil pipelines. These interests include a 28% interest in Poseidon Oil Pipeline Company, a 360-mile network of offshore pipelines with diameters ranging from 16 to 24 inches and capacity of approximately 400,000 barrels per day. While we must wait for the waiver or expiration of certain existing rights of first refusals before we can complete the acquisitions, we believe that if we are successful in acquiring these pipelines that they will complement our existing infrastructure and enhance our ability to provide attractive capacity and market optionality to producers as well as our refining customers onshore in Texas and Louisiana.

We have made significant progress on our truck station in West Columbia, our pipeline enhancements, and the development of our crude terminal in Texas City. We expect these integrated projects to be fully operational by the end of the first quarter next year.

Also in Texas, we are facilitating the return to commercial operations of a 15,000 barrel a day refinery in Wilson County, Texas, a focal point for Eagle Ford production operations. For three years we will have an exclusive crude oil supply contract, a profit-sharing agreement from the sale of the refined products, and priority rights to further develop a permanent crude oil gathering and marketing operation in and around the refinery footprint.

In Wyoming, we have recently purchased an approximate 90% interest in a 3,500 barrel per day refinery located in Converse County, to which we have been supplying crude oil since 2010. With the refinery, we are also purchasing an approximate 90% interest in some 300 miles of abandoned 3-inch to 6-inch pipeline that we believe can economically be returned to crude oil service as an early delivery system for crude oil production from the emerging Powder River Basin portion of the Niobrara Shale.

Because of these and other identified opportunities, we are in the process of expanding our crude oil trucking operations by 40% with new tractors and crude-capable trailers. Consistent with current practices, we will obtain the use of those tractors and trailers under third-party operating leases.

While we had hoped to see some contribution from these growth initiatives in the current quarter, most of the run rate contribution will begin to be realized in the new year.

Before I turn it over to Bob to discuss in greater detail the reported results, I would like to recognize the contribution of our employees. Because of their dedication to safe, responsible, and efficient operations, we continue to work together to be able to deliver increasing long-term value for all our unitholders.

Thank you, Grant. I will discuss the key differences in our third-quarter results for 2011 as compared to the third quarter of 2010, and then discuss the year-to-date results. My discussion will focus on our segment margin, as fluctuations in our revenues resulting from changes in the commodity price levels of crude oil, petroleum products, or chemicals like caustic soda do not have a corresponding impact on our earnings or available cash flow.

I will also discuss our results in terms of our three reporting segments -- Pipeline Transportation Services, Refinery Services, and Supply and Logistics. Effective with the first quarter of 2011, we now include what was formerly our Industrial Gases segment within Supply and Logistics.

For the 2011 third quarter we reported available cash of $37 million, a new record for Genesis. Each of our segments contributed to this increase in available cash through a combination of improved results from existing operations and acquisitions subsequent to the third quarter of 2010.

2011 third-quarter available cash was $8.9 million more than third-quarter 2010 available cash of $28.1 million. Net income attributable to the Partnership for the third quarter of 2011 was $19.1 million or $0.27 per unit as compared to net income attributable to the Partnership of $5.1 million or $0.12 per unit for the third quarter of 2010.

Turning to our operating segments, results from our Pipeline Transportation segment improved to $16 million, representing a $4.1 million increase over the third quarter of 2010. Our acquisition of a 50% interest in the Cameron Highway joint venture in November 2010 contributed $2.8 million to this increase. Our pro-rata share of distributable cash from Cameron Highway has been negatively affected over the past two quarters, due to planned improvements to offshore field facilities by producers at fields connected to the Cameron Highway system.

Pipeline Transportation segment margin also increased due to an increase in throughput volumes on our onshore crude oil pipelines of 10,977 barrels per day. The increase in total onshore pipeline volumes is attributable primarily to the Texas Pipeline System. Here we saw increased demand by refiners connected to our system for the sweet crude from the shale plays in Texas.

Refinery Services segment margin for the third quarter of 2011 was $18 million, an increase of $1.8 million from the comparative period in 2010. Revenues related to our NaHS activities increased over the prior quarter as a function of an increase in the average index price for caustic soda. NaHS sales volumes decreased 5.7%, due to decreases in volumes sold to mining companies in the export market and planned maintenance at some of our pulp and papers customers' facilities.

Difficulties in mining companies' negotiations with their work forces led to a slowdown in foreign mine activity. However, increased sales volumes to domestic mining customers likely offset these decreases.

The average index price for caustic soda rose $162 per dry short ton or 43%. However, the pricing in our sales contracts for NaHS included adjustments for fluctuations in commodity benchmarks, freight, labor, energy cost, and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region, and supply point.

Our raw material costs related to NaHS increased corresponding to the rise in the average price for caustic soda although operating efficiencies at several of our sour gas facilities, favorable management of the acquisition and utilization of caustic soda in our operations, and our logistics management helped offset these costs. Caustic soda sales volumes improved by 9.3% over the third quarter of 2010.

Our economies of scale and logistics capabilities allow us to effectively market caustic soda to third parties, including many of the same parties who acquire NaHS from us. We also perform additional services for refiners including, among others, handling sulfidic or spent caustic.

Supply and Logistics segment margin was $18.9 million in the third quarter of 2011 compared to $11.2 million in the third quarter of 2010. As mentioned above, Supply and Logistics now includes what we formerly reported as our Industrial Gases segment, and we have adjusted our 2010 reported segment results to reflect this change. The increase in segment margin resulted primarily from the increased volumes, operating efficiencies, and changes we made in some of our existing crude oil and petroleum products' commercial arrangements.

Increased production from new sources of crude oil such as the shale plays in Texas and Wyoming have increased demand for our services. Volumes we handled in the third quarter of 2011 as compared to the same period in 2010 increased 5%. The Supply and Logistics segment margin increased $2.9 million from the addition of the black oil barge transportation business acquired from Florida Marine on August 9, 2011.

Interest cost, corporate, general, and administrative expenses, maintenance capital expenditures, and income taxes to be paid in cash also affect available cash before reserves. Interest cost increase for the third quarter of 2011 as compared to the third quarter of 2010 by $5 million primarily as a result of the issuance of unsecured notes in November 2010.

Corporate cash, general, and administrative expenses increased by $1.9 million primarily as a result of personnel additions and other costs to meet the needs resulting from growth of the Partnership. Other items affecting available cash before reserves were an increase in the proceeds of sales of surplus assets of $3.3 million, offsetting an increase in maintenance capital expenditures of $1.5 million, primarily related to our fleet of vessels utilized in our Supply and Logistics operations. While maintenance capital expenditures were higher in the quarterly period, we expect the annual total for 2011 to be between $4 million and $5 million.

In addition to the factors impacting available cash before reserves, net income included the effect of several non-cash charges and credits. Depreciation and amortization expense totaled $4.6 million for the third quarter, an increase of $1.1 million between the quarterly periods. Additionally, net income also includes the effects of unrealized gains or losses on derivative contracts that are not included in available cash until they are realized. In 2011 unrealized gains of $4.4 million were included in net income and excluded from available cash, as compared to $2.9 million of unrealized losses that were included in net income and excluded from available cash in 2010.

Net income is also affected by the non-cash effects of equity-based compensation charges and credits. In 2011, credits to equity-based compensation accruals increased net income by $900,000. In 2010, charges to equity-based compensation accruals decreased net income by $5 million.

Differences between the cash distributions from joint ventures and the income effect of those joint ventures are also adjustments between available cash and net income. Distributions exceeded earnings from these joint ventures by $3.7 million in 2011 and $200,000 in 2010.

Lastly, 2011 net income included the effects of approximately $1 million of costs for activities related to the acquisition of assets or growth opportunities, as compared to $400,000 in 2010.

I will now discuss the principal differences between the first nine months of 2011 and 2010. For the nine-month period of 2011 we reported net income attributable to the Partnership of $43.5 million or $0.65 per unit as compared to net income attributable to the Partnership of $26.2 million or $0.48 per unit for the comparative period in 2010. Available cash before reserves generated during the first nine months of 2011 was $100.9 million compared to $72.3 million for the same period in 2010, an increase of 39.5%.

Segment margin for the nine-month period of 2011 was $149.8 million, an increase of $41.9 million when compared to the same period in 2010. Results from our Pipeline Transportation segment improved $16.9 million to $50.6 million when compared to $33.8 million for the first nine months of 2010. Our pro-rata share of distributable cash generated by Cameron Highway contributed $13.8 million to this increase.

Volumes on our Texas Pipeline System increased by 19,740 barrels per day as demand by the refiners connected to the pipeline increased. Refinery Services segment margin for the first nine months of 2011 was $54.9 million, an increase of $9.2 million from the comparative period in 2010.

NaHS sales volumes were consistent year-over-year. Caustic soda sales volumes improved by 11% over the first nine months of 2010.

As previously discussed, revenues were higher due to the increase in the index prices for caustic soda. However, that increase generally does not impact our operations significantly.

Supply and Logistics segment margin increased $15.8 million to $44.2 million when compared to $28.5 million for the first nine months of 2010. Similar to the quarter-to-quarter comparison, the increase in segment margin resulted primarily from increased volumes, operating efficiencies, and changes we made in some of our existing crude oil and petroleum products' commercial arrangements.

In addition, increased production from new sources of crude oil, principally the shale plays, has increased demand for our services. The volumes we handled during the first nine months of 2011 increased approximately 17% as compared to the first half of 2010, as higher demand for fuel oil and other heavy-end petroleum products helps us sustain the price environment for the products that we sell.

Also affecting available cash before reserves, interest cost increased for the first nine months of 2011 by $18 million to $26.7 million primarily as a result of the issuance of unsecured notes in November 2010 and an increase in the average outstanding balance on our credit facility over the nine-month periods, attributable primarily to acquisitions subsequent to the third quarter of 2010.

Corporate cash, general, and administrative expenses increased by $3.5 million. Approximately $1.9 million related to increases in payroll and related costs as our personnel needs have grown with the growth of our Partnership. $1.4 million was related to employees' exercises of stock appreciation rights. Other items affecting available cash before reserves were an increase in proceeds from sales of surplus assets of $3.3 million, offsetting an increase in maintenance capital expenditures of $1.4 million primarily relating to our fleet of vessels utilized in our Supply and Logistics operations.

In addition to the factors impacting available cash before reserves, net income included the effect of several non-cash charges and credits. Depreciation and amortization expense was $42.7 million for the first nine months of 2011, an increase of $2.3 million from the same period in 2010.

Available cash before reserves included cash distributions from our equity investees of $15.3 million for 2011, while net income included only the net income we recorded from those investees totaling $3.4 million, a difference of $11.9 million. In 2010, this difference was approximately $900,000 as we did not own our interest in Cameron Highway until the fourth quarter of 2010.

In 2011, unrealized gains of $4.6 million were included in net income and excluded from available cash, as compared to $800,000 of unrealized losses that were included in net income but excluded from available cash in 2010. Lastly, 2011 net income included the effects of approximately $3.5 million of costs for activities related to the acquisition of assets or growth opportunities, as compared to less than $600,000 in the 2010 period.

Grant will now provide some concluding remarks to our prepared comments.

Thanks, Bob. As we mentioned at the beginning, the third quarter was a busy one for us. We are not exactly sitting around. We are excited about continuing to identify and capitalize on the opportunities presented to us by our increasingly integrated operations and given our areas of commercial and operating expertise.

Our business is not as complicated as some people might think. We handle crude oil via truck, rail, barge, and pipelines upstream of terminals and refineries. We perform sour gas processing, i.e., sulfur removal, under the conceptual equivalent of a percent-of-proceeds type contractual arrangement, as well as other services inside our refinery customers' fence. We handle the bottom end of the refined barrel and intermediate refined barrels via truck, rail, and barge into and out of terminals and refineries.

We have been what I would characterize as very conservative in managing the Partnership's capital structure. Pro forma for our equity raise in July and anticipated run rate EBITDA from the Florida Marine acquisition we closed in August, our total adjusted debt-to-EBITDA is around 3.1 times. Given the other commercial initiatives we are beginning to realize, it's probably closer to 2.7 to 2.8 times.

We have around $400 million available under our committed revolver through mid-2015. As a result, if we are successful in ultimately closing the $200 million pipeline transaction we announced last week, while our leverage ratio might increase less than a turn, we have absolutely no need to raise equity or otherwise access the capital markets.

We have increased the distribution to our unitholders for 25 consecutive quarters. This is the 20th quarter during such period that we have increased the distribution by at least 10% over the year-earlier quarter. We look forward to continuing to deliver and keeping that streak intact.

As always, we are proud of our opportunity to work with a great group of folks, their immense contributions and their commitment to providing safe, responsible, and efficient services to our customers. With that, I will turn it back to the moderator for any questions.

(Operator Instructions) Ron Londe, Wells Fargo.

Thanks. Wanted to get a little more information on the two or three recent announcements you made today about the Wilson County refinery, facilitating that coming back, and the Wyoming refinery. Can you give us an idea of what the cost involved is going to be and what maybe the EBITDA run rate could be expected there?

The initial capital on the two opportunities is around $25 million to $30 million, and we would anticipate conservative annualized run rate EBITDA of, say, $7 billion to $10 million a year.

Does that include the pipeline refurbishing?

No; we have not included any of that in those numbers. Ultimately, that is something that would be a project over 2012. Our initial indications based upon our due diligence is that order of magnitude for an additional $5 million to $10 million that we can reinstitute safe, responsible service from the acquired pipeline.

Okay. The refinery where you are going to take a 90% interest, can you go into some of the economics behind that refinery? Is that refinery currently operating? Is it shut down?

We have been supplying, as we said in the statement. It resumed commercial operations in August of 2010. It is a very simple refinery. We have been supplying it on the crude oil side since August of 2010.

It basically makes three products, diesel, a naphtha-type product, and then a bottom of the barrel. As a result of our operating experience for some 15 months and given the economics that we have seen, as well as the optionality of ultimately developing the gathering marketing pipeline opportunity in and around Converse County, which is the hotbed of the Powder River Basin of the Niobrara Play, we felt that it was a very good investment for the unitholders.

Okay. The Wilson County, Texas, refinery, can you go into what the profit-sharing arrangement would be there and some of the other terms of that deal?

Again, it is formula-driven, based upon the gross margin generated by the refinery. But our endeavor there is really to establish a beachhead, so to speak, for the gathering and marketing of crude oil to not only facilitate the consumption at a local market but also to provide producers optionality of taking their Eagle Ford production to multiple markets from that point.

Okay. To get into the statistics a little bit, the CHOPS volumes were about 90,000 barrels a day. Have you received any news about when the Mad Dog might come back on?

We are anticipating based upon that -- it's likely or potential to come up in late November. Obviously, during the quarter, there were some other maintenance turnarounds, as well as six days during September that for precautionary purposes during tropical depressions, which is normal in the Gulf of Mexico in that time of year, all of the production was shut down.

Okay. Also NaHS was down about 5%. Do you expect that to recover?

What is your feel right now about -- we have seen copper prices decline. We have seen less development activity in the mines that you serve, or the potential production out of those mines. It's just seemed to indicate that there were some extraordinary items that probably affected the quarter. But what do you see overall going on in the customers that you serve?

I will ask Steve to respond to that.

We saw two things in the quarter. The first was the traditional period for pulp and paper in the third quarter is a little bit slower than the rest of the year; plus they had some unplanned outages; as well as their sentiment was -- lower their inventories a little bit given the overall global macroeconomics. We are seeing them come back strong, though, at the start of this quarter.

In the mining industry, domestic mines were very strong. They still believe that production needs to remain very high. They need to bring on an additional mine globally every year to meet the global demand.

Specific to our business, we saw two large mines in South America had work stoppages. Both of those mines though -- one in Peru is back online. They sent a management team in; and as maybe typically what you see, they are using more today than they were before the strike.

So we always like to get started off on a good first month in every quarter. And our October was the strongest month in terms of NaHS sales that we have seen in the last 18.

Okay. Very good. Thank you.

John Edwards, Morgan Keegan.

Yes, just following up on the NaHS question, so the work stoppages are behind you. I think you said you are seeing the strongest NaHS demand in 18 years. Is that right?

No, we are just seeing a trend upward to start this quarter. Not years -- over the last 18 months or so.

Oh, 18 months? Okay. Okay, all right, so you're seeing -- but not unless you are seeing sales come back to more levels of what you were expecting?

Correct.

Okay, all right. Then if I could ask Grant on the Poseidon transaction, just I think you indicated in your press release, it was a week or two ago, regarding how you believe that gave optionality, etc. Do you guys -- are you guys able to get that optionality with having basically a minority stake in the proposed pipelines?

The short answer is yes, and we don't have a -- I mean, our main business in terms of being a pure midstream service provider is offering producers and refiners the most economic alternatives. There is CHOPS and Poseidon that various locations are capable of the produced oil going in either direction, so to speak.

So we -- in one sense, it is our desire to have an ownership position in Poseidon. We have become relatively economically agnostic as to which direction the oil wants to go.

Okay, great. All right. Then on these new refinery projects here, is it -- it didn't say who the sellers were. Is that something that you can provide?

No.

Okay, all right.

That is the short answer.

No problem. Then out of the $25 million to $30 million of initial CapEx, about how much is going to each?

The vast majority of that is going to Wyoming, the purchase of it. We are not purchasing an interest in the Wilson County refinery.

Okay, okay, and then -- all right. So what exactly does it mean that you're facilitating the return to commercial operations?

We are lending some operational expertise and certain construction services to bring the refinery back to safe, responsible operating capability. Again our focus is to not only facilitate what we believe to be a high-value localized market, but also to develop ultimately a gathering and marketing operation with the potential -- we have a priority right to build additional tankage and pipeline interconnects on the refinery site for three years, to develop an outpost smack-dab in the middle of the Eagle Ford production.

Okay, great. All right. That's all I have. Thank you very much.

TJ Schultz, RBC Capital Markets.

Hey, guys. Good morning. Good quarter. Just following up on that last point, I had just a point of clarification. So $25 million to $30 million initial capital; and then $5 million to $10 million for the pipeline refurbishment, which I assume is in Wyoming.

Does any of this include the opportunity for the oil gathering and marketing around the Wilson County footprint? Then if not, what is that level of investment opportunity and timing on that project?

No, there is no capital in that number for additional tanks or other pipeline interconnects in and around the Wilson County. But as we said, we have an exclusive supply agreement for three years. And we believe that we will make a usual and customary margin upstream of the facility as well as a sharing arrangement in the profits to be generated by cracking the crude that we take to the refinery.

So near-term cash flow, while we are developing our longer-term strategy of putting in infrastructure and trucks and pipelines and tanks in that part of the world.

Okay. Then on the trucking expansion, obviously there is high demand for trucking services across the landscape. Any concerns on securing the amount of truck services you think you can utilize, or concerns on drivers?

Obviously there is somewhat of a lead-time associated with obtaining new equipment. This is -- we are taking delivery and have already started taking delivery in this quarter of additional trucks and trailers.

We are working hard to hire drivers and train them and emphasize the safety and responsible operations that we have embedded in our culture. But we have not had any issues of getting jockeys for the horses, so to speak.

Okay. Thanks. Just one last thing. Can you provide any initial feedback on the Florida Marine business that was acquired? Any positive surprises since the acquisition closed? And then your ongoing thoughts there with placing some of the fleet into crude oil service?

We are very satisfied with the acquisition. As you can see, we had a significant contribution for the 50-some-odd days that we owned it during the quarter. Obviously we didn't own it for the whole quarter, so arguably the run rate EBITDA from the acquisition is not reflected in the reported results.

Quality -- very high-quality assets, very high-quality people. And for the first time since we have been in the integrated barge transportation business we have the flexibility from a scale point of view to optimize our operations. So we are very excited about the acquisition.

As we have stated, currently I think the number is three out of our 50 barges have vapor recovery currently, which would allow them, if you will, to move crude oil. Another 22 were originally designed and constructed and subbed out, as we say, to retrofit without serious downtime or service interruptions vapor recovery. And we certainly see increasing demand for the ability to move crude oil via barge.

Okay, thanks, guys.

Ethan Bellamy, Robert W. Baird.

Grant, could you clarify for me please the different rights of first refusal -- and Marathon has a right of disposal on the asset, the Marathon acquisition, please?

Well, I don't know that we are going to -- clearly as we said the 36% membership interest in Poseidon is owned by an affiliate of Shell; and 36% Poseidon membership interest is owned by an affiliate of Enterprise. Shell affiliate has 71% interest in Odyssey. Both of those have not atypical right of first refusal or transfer restriction opportunities.

There are certain other -- our motivation is to ultimately be successful in acquiring the interest in Poseidon. In our agreements with Marathon they have the right under certain conditions, primarily with some assets that are in essence associated with Eugene Island or Marathon Offshore Pipeline, some smaller things that were really not part of our ultimate interest to dispose of.

So should I take that to mean that -- just put it simply that Enterprise could step up and outbid you if they wanted to and sell?

Well, the typical mechanic is that the existing owners or members of an LLC would have the right to match.

Okay. Can you handicap for us what you think -- do they have interest? Do you think there is some chance that the deal wouldn't close for those reasons?

I can't speak for Enterprise or Shell.

Okay; thank you.

(Operator Instructions) John Tysseland, Citigroup.

Hi, guys. Thanks. The announced investments in the refineries appears relatively small, and the refiners themselves also appear relatively small. Is the idea there that these assets should just basically benefit from attractive crude acquisition costs versus I guess larger-off refiners with economies of scale in the Gulf?

You know, these refiners -- or two refinery footprints are located in the middle of the developing crude oil plays driven by shale development. So the Eagle Ford in the case of Texas, and Niobrara in the case of Wyoming.

As a result, there are probably favorable lease acquisition opportunities. But importantly, processing the local crude oil and upgrading it in situ, so to speak, is a high-value proposition. Again I want to emphasize that our primary focus is using both of these locations as opportunities for us to develop further gathering, marketing, and transportation opportunities for the production.

Okay, great. Fair enough. Then is the -- I guess the way we should think about these assets is more or less that the spread differentials benefit these smaller refiners. Even though they might not have economies of scale, they have beneficial crude acquisition costs; and you can sell the products locally, I suppose. Is that fair?

Under current economics the relative processing or crack spreads are quite high.

Okay. Then secondarily, the truck expansions that you mentioned, can you provide how many crude oil trucks you currently control and what that ramp-up looks like over the next year? I was unsure whether this announcement was incremental or just a reiteration on trucks that you previously announced coming into service.

This is an incremental expansion. We currently operate in round terms 76 crude oil tractors and trailers -- as opposed to 76.5 -- and so this is 30 on top of that.

Basically given our -- the level of activity that we anticipate in and around West Colombia when we become operational in Wilson County, Texas, and the Eagle Ford, and other areas in which we operate including West Texas and the Permian, as well as some of the developing plays in Louisiana and Mississippi that we are trying to -- we know that we can put these to work as soon as we get them in service and get our drivers adequately trained in safety and responsible operations. So we think that we should be able to handle significant incremental barrels as a result of this fleet expansion.

So is that 76 going to over 100 over the course of the next couple quarters? Or should we think about that over the next year?

The 30 should be all operational by the end of this quarter.

Okay, excellent. Then have there been any early indications on the ROFR from the pipeline acquisition so far? I mean if you look back at CHOPS, the ROFR was not executed by Enterprise on that asset.

Is there any reason to believe that it would be this different this time around? Or do you expect it to take the full 45-day waiting period?

We are just not in a position to be responsive to that at this point, John.

Okay, fair enough. Thanks, guys.

Kelly Krenger, Bank of America.

Good morning and thanks for taking my question. Grant, you mentioned I think earlier in the call or in your scripted remarks about on a run rate EBITDA basis you are at around 3 times or 3.1 times total debt-to-EBITDA.

Yes.

I was just curious in terms of if you could walk us through the bridge to that number, or what your debt-to-EBITDA number is, I guess, and what is included in that in terms of adjustments. Does that include adjusting for CHOPS being down for the last -- or part of CHOPS being down for part of the last couple quarters? Certainly having that barge business for (technical difficulty) 55 days in the quarter. But just if you could tell us what the EBITDA run rate number is and how you are -- what components you're using to get there.

Well, when we say adjusted, it is consistent with our revolving credit facility. We -- our lenders as well as ourselves -- exclude 90% of the hedge value of our inventory at any point in time for purposes of covenant calculations, either from a compliance point of view or where we are in the pricing grid. So if you look at the outstandings under our senior secured credit facility at 9/30 you would [freeze] call it $368 million. What was the outstandings for the -- 48 of that was associated with hedged inventory of crude oil as well as refined products that --

The 90%.

That's the 90% number. So call it $320 million is adjusted debt; so that is your numerator, Kelly. Our adjustments from an EBITDA point of view are only, in essence, we are looking at actual numbers, but we are reflecting over an LTM basis instead of having the run rate EBITDA of 53 days of FMT, of having of it for the 365-day period.

Yes, okay. Then you're not making any adjustment for the reduced volumes at CHOPS?

No, not at all. Relative to that, I mean we reported $2.8 million for the quarter coming out of CHOPS. We certainly didn't buy it for $2.8 million; we didn't buy it for the $6 million of distributions we saw in the first quarter when in essence was the last quarter that the one particular field was up and running.

We bought it for purposes of what we believe are extraordinarily realistic numbers of $12 million to $14 million per quarter. Whether or not that occurs in late 2013, '14, or '15, we are not overly concerned about that.

We did during the quarter -- I think that the producers of the one particular field announced a step-out well of a previously undrilled fault block in the dedicated field, and announced over 4 billion barrels of oil in place, all of which is contractually dedicated to us. Using a reasonably conservative recovery factor, the oil in place of around 30%, that is 1.2 billion barrels from one field, which is contractually dedicated for the life of that field to CHOPS.

Okay. I guess bottom line, once CHOPS -- once the facility gets to where they were prior to whenever it was, April or so, it would seem that the run rate should start to improve. So it seems that relevant to that [healthy] rate would provide a little bit of upside, is the way I am talking [on] it.

I think that, in combination with the $7 million to $10 million of EBITDA run rate that we discussed earlier relative to our new initiatives, as well as the $7 million to $10 million EBITDA run rate from our Texas activities, including the terminal in Texas City, those went into our conceptional calculation of basically being a lot closer to 2.7, 2.8 turns as we currently view our businesses.

Okay, okay. Thank you very much.

John Edwards, Morgan Keegan.

Yes, hi. Just a follow-up. What is the product mix coming out of these refineries, Wilson and Wyoming?

As is a general proposition you could think of it as 40% diesel cut, 25% naphtha cut, and 35% bottoms, if you will that can basically feed -- be a cat feed if you will, or [garnered] into cat feed for more sophisticated refineries.

Okay, and which one is that from?

That's the bottoms. (multiple speakers)

No, I mean which refinery?

Oh, I'm sorry. That would be generally the same across the two locations.

Both? Okay. Great. All right, thank you.

We have no further questions in the queue at this time. I would now like to turn the floor back over to management for closing comments.

Well, thanks, everybody, for joining us and we will talk to you in 90 days, if not sooner. Thank you.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.