CVR Energy Inc (CVI) 2007 Q4 法說會逐字稿

Greetings and welcome to the CVR Energy fourth quarter earnings conference call. At this time all participants are in a listen only mode. A brief question and answer session will follow the formal presentation. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Stirling Pack, Vice President of IR for CVR Energy. Thank you, you may begin.

Thank you Joe. Thank you everyone for being here this afternoon, I think you'll find it to be a most interesting call, and we appreciate your taking time out to listen to our discussion of the results.

Prior to discussion of our 2007 annual and fourth quarter results, we are required to make the following safe harbor statement. In accordance with federal securities laws, the statements in this earnings call relating to matters that are not historical facts, are forward-looking statements based on management's belief and assumptions using currently available information and expectations as of this date, and are not guarantees of future performance and do involve certain risks and uncertainties, including those filed with the Securities and Exchange Commission.

Yesterday after the market closed, CVR Energy issued our annual 2007 and fourth quarter 2007 results, this is our first annual release as a public company, and our second investor call. The release can be found on our website at www.cvrenergy.com. With me today are Jack Lipinski, Chief Executive Officer; Stan Riemann, COO; Tim Rens, CFO; and other senior management of CVR Energy. Jack will speak first, after which Tim will follow with a discussion of the reported financial results. Jack and Stan will further discuss results of operations and provide relevant industry context. We will conclude with a question and answer period. Jack?

Okay, thank you Stirling, and thank you all for joining us on this call. 2007 was a transitional year for CVR Energy in both business segments. We successfully executed a major turnaround of our refinery, substantially completed a major capital expansion program, experienced first hand the devastating effects of a 500 year flood, its aftermath and extraordinary recovery of our operations.

In October we concluded an offering of CVR Energy Inc. shares, which are now traded on the New York Stock Exchange, and transformed CVR into a public company. As disclosed in the registration statement of CVR Energy, we have now filed an F1 registration statement for an MLP of our nitrogen fertilizer business. Tim will discuss this in greater detail.

As you know, under SEC rules, because there is a registration statement on file, we are severely limited in what we can say about this filing. We believe that CVR is well positioned within our industry to take advantage of markets and various opportunities as they arise. Our revamped and expanded refinery now has the capability of not only processing crude at higher rates, but it can run significant quantities of lower cost, heavy sour Canadian crudes.

Our fertilizer plant is the lowest cost producer of ammonia and urea ammonium nitrate solution in North America, and it is benefiting from higher fertilizer prices.

Right now I'd like to ask our CFO, Tim Rens, to discuss our financial results, after which Stan and I will rejoin the discussion. Tim?

Thank you Jack. I'm going to recap our annual results, then discuss in more detail our fourth quarter financial results, our balance sheet, and CVR Partners S1. Before I discuss the reported results for the quarter, I'd like to remind everyone of a few items that should assist in understanding the financial results. First, our inventory methodology is FIFO, as opposed to LIFO, which is used by many independent refiners. Also, our results are impacted by the unrealized gain or loss on the long term hedge position. To assist in better understanding the impact of the unsettled swaps on our results, we will report net income adjusted for unrealized gains or loss on the debt cash flow swap.

As a result of a restructuring associated with the IPO, certain share based plans, of which the majority of the obligation resides at our sponsor shareholders, and will not be paid by CVR Energy, were required to be revalued at the IPO value. The increase in the value of the plan significantly impacted our fourth quarter results. Lastly, results were impacted by one time IPO costs and costs related to the 2007 mid year flood.

I will discuss operating income by segment, and although both segments' operating income are impacted by SG&A allocations, a discussion of SG&A is more meaningful on a consolidated level.

As stated in our press release, we reported a consolidated net loss of $56.8 million for the full year 2007, versus income of $191.6 million for the full year 2006. We had net income, adjusted for a $62 million unrealized hedge loss, of $5.2 million for 2007, compared to $115.4 million of net income, adjusted for a $76.2 million unrealized hedge gain, in 2006. The 2007 results include $41.5 million of net costs associated with the flood, and $43.5 million of share based compensation expense, of which $25.2 million relates to plans of our sponsor shareholders, which are required to be pushed down to us under GAAP.

For the quarter ended December 31, 2007, we reported a net loss of $15.9 million compared to a net income of $20.8 million for the comparable period in 2006. Excluding the impact of the unsettled swap positions, we had an adjusted net loss of $13 million in the fourth quarter of 2007, compared to an adjusted net loss of $7.1 million in the fourth quarter of 2006. You might recall from our original prospectus that our exposure to the swap reduces significantly at the end of the second quarter of 2009, and expires completely at the end of the second quarter of 2010.

The quarterly results for 2007 include $7.2 million of net cost associated with the flood, and $32.2 million of share based compensation expense, of which $23.5 million relate to plans of our sponsor shareholders.

Operating income for our petroleum segment was $33.2 million for the fourth quarter of 2007, compared to $12.1 million for the fourth quarter of 2006. The results for the fourth quarter of 2007 benefited significantly from a FIFO gain of $25.2 million, compared to a FIFO loss of $20.5 million for the comparable period in 2006. Although there was an increase in crude oil throughput in the fourth quarter of 2007, industry margins in the region were down slightly versus 2006, and against higher crude prices.

Refinery direct operating expenses, exclusive of depreciation and amortization, were $38.8 million for the fourth quarter of 2007, which was substantially the same as the $38 million in the same quarter of 2006.

Operating income for our fertilizer segment was $11.7 million for the fourth quarter of 2007, compared to $2.8 million for the fourth quarter of 2006. Higher prices accounted for all of the increase and were somewhat offset by lower production volumes, higher operating expense, and a higher SG&A allocation. Direct operating expenses were $18.5 million for the quarter, compared to $16.5 million in 2006, with the increase primarily the result of repairs on a major piece of equipment in the UAN plant.

Improvement to operating income from the segment was somewhat offset by an increase in consolidated SG&A expense from $29.4 million in the fourth quarter of 2006 to $51 million in the fourth quarter of 2007. The most significant contributors to this increase were the non-cash expense associated with our share based compensation plan, and a $10 million one time fee associated with determination of management agreement commensurate with our IPO.

I'll now turn to some brief comments regarding cash flow and current liquidity. For the fourth quarter we did spend $28.9 million in capital expenditures, primarily on the completion of the CCR. Total outstanding debt is currently $528 million, excluding $124 million of [dajay] earnings, under terms of a one year deferral entered in August of 2007 as a result of the flood. As of March 10, 2008, the company and its subsidiaries had $13.8 million of cash on hand, and $54 million available under revolving credit facilities.

We still anticipate a significant insurance recovery related to the flood damage and loss of production, as represented by the $85.3 million accounts receivable that was recorded on our balance sheet at the end of December 31, 2007. We continue to work through the claims process but cannot accurately predict when it may come to conclusion. We continue to aggressively pursue the recovery.

Income tax expense for the quarter ended December 31, 2007 was $12.1 million, or 78% of income before income taxes, as compared to income tax expense of $8.8 million or 40% of earnings before income tax for the three months ended December 31, 2006. The annualized effective tax rate for 2007 is higher than the comparable annualized effective tax rate for 2006, primarily due to credits, which were generated in 2007 from the production of ultra low sulfur diesel fuel applied to a reduced level of earnings before tax in 2007. The company anticipates that the quarterly effective rate will return to more normalized levels in 2008, excluding the recognition of approximately $35 million in tax credits for additional ultra low sulfur diesel production.

Before I turn things over to Jack I would like to briefly mention the S1 filing that was completed by our currently consolidated subsidiary, CVR Partners LP. As mentioned earlier, under SEC rules because there is a registration statement on file with the SEC, we are severely limited in what we can say about the filing. In short, CVR Partners LP filed a form S1 registration statement with the Securities and Exchange Commission to sell 5,250,000 common units of the partnership for an estimated net proceed of $93.4 million. After the IPO we will own approximately 87% of the partnership units, which we expect will generate $52 million per year in minimum distributions to CVR Energy. Jack Lipinski, our CEO, will next highlight some recent significant events and discuss our business segment operations. Jack?

Thank you Tim. Let me recap some of our petroleum operations for last year, and the fourth quarter in particular. Crude throughput at the refinery averaged 110,300 barrels a day during the fourth quarter of 2007. This compares to 95,900 barrels a day for the same period in 2006. This is a new record for the plant and is reflective of our successful capital expansion program. On the way to achieving this throughput level, seven individual units set new monthly operating records during the quarter. Not only did we process more crude, the amount of lower cost heavy sour crude in our slate increased substantially. During the fourth quarter of 2007 we averaged approximately 21,000 barrels per day of heavy sour crude, as compared to 2,700 barrels a day in the fourth quarter of 2006.

Direct operating expenses dropped from $4.31 a barrel to $3.82 a barrel quarter-over-quarter. Direct year-over-year comparisons are difficult, primarily because of last year's turn around and the flood event, which we've described before, and Tim explained in detail during his presentation. Our fourth quarter results do not reflect operational improvements from our new continuous catalytic reforming unit, which we call our CCR. If you recall from our previous investor call, we expected this unit to start in mid-December. Construction delays moved our start up into mid-January, when the unit started, and the unit is now operational.

We continue to benefit from our location in pad two, group three, the group is fundamentally undersupplied, which results in higher margins for our products as compared to surrounding markets. We continue to expand wholesale lag marketing in both volumes and sales locations. We've also increased sales of ethanol blended gasoline at our wholly owned facilities. Our proximity to Cushing Oklahoma and its crude hub allows us to access virtually an unlimited variety of crudes. We also gather up to 25,000 barrels a day in mid-continent crudes. As you know we blend various crudes with our gathered crude to provide the refinery with the most economical crude slate.

In the fourth quarter of 2007 economics drove us to maximize heavy Canadian crude, primarily WCF. We continue to expand our crude gathering activities, we have acquired during the quarter additional barrels in Kansas and Oklahoma, and have now expanded into Nebraska. I'll turn the call over to Stan now, our COO, who will review our nitrogen fertilizer business.

As background for the nitrogen fertilizer business, I'll revisit the key advantages of the wider competitive strength. CVR's nitrogen fertilizer facility is the newest nitrogen fertilizer facility in North America, and is the only facility that utilizes a petroleum coke gasification process. We are the lowest cost producer in North America at prevailing natural gas prices of ammonia and urea ammonium nitrate solution, which we refer to as UAN.

Prices for both ammonia and UAN are significantly above historic levels and reflect strong demand for nitrogen fertilizers, driven by a growing world population, changes in dietary habits and expanded use of corn for the production of ethanol. The upward trend in prices is seen in the quarterly financial results and comparisons for '07 and '06. Higher prices continue on into 2008. Ammonia and UAN realized prices were $408 per short ton and $236 per short ton for the fourth quarter of '07. Comparatively for the same period in 2006, prices were $301 and $144 per ton for ammonia and UAN. The operating income impact of the higher prices was somewhat offset by lower sales volumes and increased direct operating expense as a result of equipment repairs.

For fiscal year 2007 we reported ammonia production volumes of 326,700 short tons versus 359,300 short tons. The variance is driven primarily by hydrogen availability to the refinery and, to a lesser extent, by the flood event.

For the fourth quarter of 2007, reported ammonia production volumes were 81,800 short tons, versus 85,400 short tons in the fourth quarter of '06. When equalizing for hydrogen delivery to the refinery during the CCR construction, the normalized production for the same period would've been 111,000 short tons for the fourth quarter of '07 and 107,900 short tons for the fourth quarter of '06.

For UAN in '07, we reported production volumes of 576,900 short tons, versus 633,000 short tons in '06; the variance primarily due to the flood event itself. For the fourth quarter of 2007, we reported UAN production volumes were 144,300 short tons, versus 168,100 short tons in the fourth quarter of 2006; the variance primarily due to equipment repair.

At this time, I'll turn the call back to Jack for some closing remarks. Jack?

Okay; thanks, Stan. This year we continue working toward completion of our plant-wide expansion program. In that regard, we scheduled a shut down of one of our two large diesel hydro treaters, to effect an expansion, during the January/February seasonally low margin period.

We have additional expansion work that will be scheduled over the next seven months and we do not expect any material reductions in overall production as a result of this remaining work.

The first quarter throughput is expected to average approximately 105,000 barrels a day. This slightly lower throughput as compared to last quarter is the direct result of our expansion work on Diesel Treater number one.

We continue to optimize our crude blends around heavy Canadian crude. Heavy crude runs for the first quarter are expected to average about 15,000 barrels a day. The year ago, for the same period, this number was significantly less than 4,000 barrels a day. Even though heavy Canadian crude differentials have retreated from the lofty levels of last quarter, this crude continues to be the low cost crude component of choice.

Our new CCR is operating. As with all new equipment, we had to work through some start up issues. We've worked through them and we believe they're all behind us. The additional hydrogen produced by this unit has reduced equivalent hydrogen purchases from the fertilizer plant. In turn, the fertilizer plant produces incremental ammonia from that hydrogen.

We continue our engineering efforts on the next phase of our refinery expansion. Our goal in this project is to not only increase overall throughput, but to significantly increase our ability to process more heavy sour crudes. Meanwhile, on the fertilizer side of the business, we are continuing with our UAN expansion.

That concludes my comments and the comments of the team. Right now, I'll turn this call back over to Stirling for questions. Thank you, gentlemen.

Thank you. This is Stirling. We have now asked Joe to prepare for the queue of questions and we'll begin that as soon as you're ready, Joe. Thank you.

(OPERATOR INSTRUCTIONS).

Our first question is from Jeff Deitert with Simmons and Company. Please state your question.

Yes, it's Jeff Dietert with Simmons and Company. You were successful running 21,000 barrels a day of Canadian heavy during the fourth quarter and, did I hear you correctly? You're expecting to run about 15,000 in the first quarter?

That is correct. The differentials were historically high for particularly Western Canadian Select and other type grades in the fourth quarter. And again, the way we blend our crude is to optimize to a mid-sour blend, something between 28 and 34 API and about 1.2% sulfur.

The differentials on heavy Canadian have fallen substantially over the quarter and we had other options to run that actually improved our overall profitability. We don't look only at crude discounts as a way of improving our profitability. It's also yield.

So, other crudes, which may be more expensive, actually may have given us a better yield. So, we blend, literally, weekly and buy, over the course of the entire quarter as we go forward, to buy the most economical crude blend that we can, at the time the market allows it.

And so, is the 21,000 barrels a day kind of the upper limit on Canadian heavy that you could handle on a consistent basis?

At the current time, it might be able to go up slightly because, as we raise crude rates in the future, our stated capacity, by the end of the year, will be over 115,000 barrels a day. So, proportionately, on a blend basis, you would be able to go up on that rate somewhat.

So, again, we ran 110,000 for the quarter. This coming quarter we believe we'll run approximately 105,000. By the end of the year, we expect to be running north of 115,000. And, in order to accommodate 21,000 barrels a day of heavy Canadian, we then blend more sweet crude to stay within our blend component.

So because of the sweet differentials and the sweet-sour differentials, particularly in this quarter, it's been advantageous for us to lower the amount of heavy Canadian. We have actually run some of the Persian Gulf crudes more, most recently.

Then, and now, on the yield side, I assume that you are producing about as much diesel as you can; the incentive's been there. Anything you can do, short-term, to improve diesel yield?

We work on that continuously. A lot of it is related to our next step of our expansion. We have some more work to do on some of our [backing] units. We are continuing to extract more diesel from the BTO cut. The plants, as configured, actually have some surplus diesel capacity, some surplus cat-cracker capacity and some surplus Coker capacity.

And depending on availability in the mid-continent for feed stocks, we do buy additional feed stocks, such as vacuum bottoms, cat-feed and naphtha. The downstream units, we were nicely surprised during our expansion that many of our downstream units actually have come in running slightly above in their design rates.

Very good. I was wondering if you had the long-term and short-term swap payable amounts for the balance sheet as of the end of the year.

The open amounts?

Right.

I don't have the unrealized balance sheet number in front me, actually, right now, Jeff. I can get you those numbers.

Okay. Thank you for your comments.

Thank you, Jeff.

Our next question is from Christina Brown, with Deutsche Bank. Please go ahead with your question.

I'm sorry; it's (inaudible). Hi, it's Paul Sankey, not Christina.

Hello Paul; how are you?

Christina's working with me but I'm going to actually ask the questions, if that's okay.

Guys, firstly on the realizations you had I was wondering, we were surprised positively by how much you made in terms of margin. Was there any inventory effect in there? I was wondering if there might've been some sort of distortion in that respect.

Yes, there was. There was about $25.2 million of FIFO gains in the quarter, in total.

Okay, which, I guess, we would expect to see every Q4?

Well, (inaudible)--.

Well, as the market's improving--.

...if prices go up, we had crude and product run up in the fourth quarter from the beginning of the quarter at the end and that's primarily what generates your FIFO gains.

Yes, okay, because I'm just working on a few of the recurring items here, if you'd like, I'm trying to strip out some of the recurring stuff. On the -- going further into that, the SG&A was obviously a lot higher than what we'd forecast. But a couple of those issues, to an extent, I guess, would be considered one-off.

Firstly, on the stock compensation....

Yes, the stock compensation for the fourth quarter was about $32.2 [million]. For 2006, that same number was about $10.3 million. So, a significant portion of that, nearly all of it in the quarter, was a result of plans that are in place, at our sponsored shareholder. And it was -- we were required to revalue those plans as a function of the IPO. So, a substantial portion of that, probably in excess of $20 million of that, would be non-recurring in nature.

In addition, we had a $10 million one-time charge that was the result of the termination of a management fee that terminated commensurate with the IPO.

Yes, that was my next question. So, do you expect any more of those now? Or is that done?

No, that's done.

So that's done as well, okay great. So you're telling me that $20 million of the compensation is a one-off effect (inaudible).

In the quarter (inaudible) in the quarter, you had about $22 million that would've been kind of non-recurring in nature. And then, on top of that, you had $10 million.

Yes, okay. I've got you and then, just going back to the fact that we were surprised on the upside by the margin performance, was there anything else? You mentioned the Canadian heavy was an obvious positive. You've talked about LIFO --- about FIFO, sorry. Is there anything else I should know about?

To a lesser extent, we've been successful in buying back entire bottoms in the dead of winter when there's no asphalt season. We were able to purchase some volumes. Whatever's built, well, it's usually not a lot but the margin on that is very significant. So sometimes, rather than running crude, or to go back to Jeff Dietert's question, why are we running less heavy Canadian?

In the first quarter, we tend to be running a little bit more vacuum tower bottoms directly to our Coker, which takes up Coker capacity.

So everything is a balance within our LP. You know, we just recently brought our new CCR out. It's gone through its shakedown cruise; we're pretty happy with what we're seeing. And we're starting to balance the refinery around this new unit.

Terrific and finally, one last one from me. On the fertilizer side, you were back in line with what we thought but I guess the market is strengthening rapidly there. Could you just talk about how the market is changing, the outlook for the year and how that's going to potentially impact your earnings? Thanks.

This is Stan Riemann. The outlook for fertilizer prices is very strong. Through all the forecasts that you see from industry experts as well as government projections on corn acres, talk to a very strong fertilizer price.

Our open book of orders, right now, represents roughly three months of production and it's significantly higher than the fourth quarter results. It'll approach $300 in [netbacks]. And we, quite frankly, see that moving up. We're looking at a very good at least first two quarters of '08 and on.

And just to fill in with what Stan was saying is we tend to take orders for several months, bill to book, and then we ship the product all year. But it's used in season, usually over a two month period. And then the industry goes back to replacing orders. And again, year-over-year, the fertilizer in realized netbacks are significantly higher than they were before.

So, as we roll off the book that was put on during last year, we expect to see improvement.

That's great. I'll let someone else have a go at it. If there's time, I might come back for a couple more; thanks.

Our next question is from [Sunio Jaguani], with Catapult.

Good afternoon; just following up to Jeff's question earlier about the payable, since it's not being used as hedge accounting, is there any reason to not include that amount as debt?

Well the problem with, right now, including it is as debt is, depending on what you're wanting to do with it is that our historical earnings are on a hedged basis. So, I mean, if you're wanting to try to understand what our debt as a function of our earnings are then you really need to look at un-hedged historical earnings. And, at that point, if you want to look at it as kind of what's our debt turn on EBITDA.

But to look at historically hedged earnings and then include the potential unrealized gain or loss in future earnings, or unrealized gain or loss as debt is probably a little bit of kind of double counting.

Well, then that's just why I just wanted to clarify because my intention is, of course, to try and say maybe just to an adjusted EBITDA calculation for the projection -- or just basically understand the obligations versus future cash flow and, since it's -- you know, we're not including the deficit from the hedges in the future cash flow, I'm guessing -- it would seem that we should include it as debt.

If you look at un-hedged....

Yes.

Yes, if you look at un-hedged -- one way to look at it is un-hedged forward cash flows and include it as debt. If you try to look at forward cash flows on a hedged basis then you should not. The key is to be consistent.

And I wanted to clarify one other thing, are there any tax impacts that might adjust the actual table amount? And I know it changes quarter to quarter, depending on the mark to market. But are there any tax implications that might inflate or deflate the actual table?

No, ultimately when you actually have realized income, it becomes taxable at that time. Your provision includes a tax on the unrealized gain or loss, but there's a deferred tax impact to that as well. So when you actually calculate your tax bill you'd only calculate it on realized gains and losses.

And then I just have one quick follow up. Once the spin off is done on the fertilizer business, I'm guessing that there would be tax implications for the parent. What can you tell us about the book basis for the fertilizer business?

The book basis for the fertilizer business right now is not the best indicator of what the total tax impacts are. There are some unique impacts on tax as you take something to an MLP. So I'd really, in an effort of caution, like to try to avoid any detailed discussion about the MLP on this call other than to say that book basis is not the only indicator of what the potential tax consequence is.

But there is some tax...?

Absolutely.

Okay, thank you.

The next question is from Jason Smith with Citigroup. Please go ahead with your question.

It's not Jason, it's another post [inaudible] situation, it's Bud Weigert here, Jason works with me. A couple of things, gentlemen, it's really housekeeping more than anything else. The underlying SG&A on guidance on operating cost going forward by division, can you just help us with that please? What was the underlying SG&A, clean if you like, for refining and fertilizers, and what guidance would you give us for operating costs on both of those businesses going forward?

Historically the typical guidance we've been giving is about a $60 million annual run rate with about $15 million of that finding its way to the fertilizer business.

Right, so I'm talking about the fourth quarter specifically, can you give us the underlying, clean if you like, by division?

I don't have the underlying clean by division in front of me. Again we primarily look at SG&A on a consolidated basis, because most of the SG&A is really a function of -- is happening at the corporate area and then allocated back down. The most significant adjustments to the SG&A again are the $10 million that we talked about, and then the number I referred to earlier was about $22 million in executive compensation. You know what, actually that $22 million is total executive compensation not just the portion that went through SG&A. So I think the SG&A piece was about $8 million. So if you look in total at those two numbers, you have about $18 million to $20 million of SG&A expense on a consolidated basis.

Right, okay. They were all pre-tax numbers, right?

Yes, they are.

Now the 7.2 flood expense, is that pre-tax as well?

Yes, it is.

Okay, great. What about OpEx guidance, Tim, going forward?

Tax guidance going forward?

No, no, OpEx, operating cost guidance.

Oh, for the year what we had typically looked at on a guidance basis was high threes, somewhere in the $3.80 to $4.00 range.

Per barrel on the refinery.

Okay, what about for fertilizers?

I want to be careful in the fertilizer business to be honest, a little bit, with the MLP out there I'm giving a lot of guidance numbers. I can tell you that we don't see anything unique on the fertilizer business right now as opposed to historical run rates, other than there's a tax abatement that rolls off the fertilizer business, and we're still working through that number.

Okay. I know you can't say too much about the filing and so on, but I guess this is probably kind of a stupid question, but once you have completed the IPO you're going to own 87% and you will obviously get distributions from that. How should we think about the tax treatment and consolidation of that 87% going forward?

It's not a return of caps, it's just earnings at CVR Energy, no different than if CVR Energy were generating those earnings today.

Right, so at the P&L level you'll still consolidate and tax accordingly?

Yes.

But on a cash basis, how will the tax work there, on the distributions?

Again when that money comes up from the partnership to CVR Energy they're going to get a portion of allocated income. So it's not necessarily getting taxed at the distribution.

Oh I see, okay, got it.

It's a partnership.

Great stuff. And I guess the final one for me and then I'll let Paul Sankey ask his other three questions. The mix on the crude slate, you've given us some numbers on, I guess we should use Western Canada Select as our benchmark.

That is the most typical crude, we do buy [loidness] and [cold lake], any number of various crudes. That one happened to be the one most easily assessable and easily traded, and also could be purchased in Cushing as well.

Okay so if I then look at the other grades then, when you talk about light crude, are we talking discounted light crude, or can you give us some guidance as to what...

Okay there are basically two types of light sweet crudes that we use to blend, one is our gathered barrel, which we effectively deliver to the refinery below WTI, significantly below WTI. Then there's WTI that can be bought at Cushing and transported to the refinery, so it's basically WTI plus the tariff to get it up our 100 miles of pipeline up our dedicated line. Then there's any number of sour crudes, whether it's domestic, onshore, could be Gulf of Mexico sours, it could be anything from Southern Green Canyon, Poseidon, there's a whole list of those. We will also access west Texas sour, but we find that one is generally not very attractive. There are some Canadian mid sours that we access, east Texas, and then there are foreign sours.

So if you could kind of guide us then toward, because what I'm trying to get a handle on is what the mix of advantaged crudes are that we should be modeling going forward. So if you could give us an idea, okay we've got 20% in Q4 was Western Canada Select, what kind of split would you give us for the balance and guidance going forward?

In our earnings release, quarter-over-quarter it's not going to change too awful much going forward. When last quarter, fourth quarter WCS was discounted at $32 or $33 a barrel under WTI, you did everything to run that crude. If you were to look at our earnings release and you take a look where we have our crude breakdown and you see sweet, light/medium sour, heavy sour, I would say that 25,000 barrels of that sweet is advantaged sweet, 20,000 to 25,000 which is our gathered crude. So if you were to take the light/medium sours, add it to the heavy sours and then subtract from that 25,000 barrels a day nominally of seriously advantaged sweet crude, you would then come to the sell balance.

Okay. Just indicative, what kind of discount did you see in the fourth quarter on the advantage sweet crude? You were talking about Wyoming sweet ...

No, no we're talking just Kansas sweet, Kansas, Okalahoma and Nebraska. I don't know if we've actually published that information, but suffice it to say that the crudes are posted, there are posted prices, then you pay for gathering, somewhere I guess between $2 and $3 a barrel roughly.

Got it, okay. That's it for me. Great, thanks very much indeed.

Thank you.

The next question is from Sara [Nanhura] with Millennium Partners; please go ahead with your question.

Hi guys, it's actually Mark Caruso. I just actually was looking -- I had two questions one was a clarification question to the tax question asked earlier. I don't know if you really quantified what the implication would be. We kind of talked that there would be a hit, but did you actually give a number or quantify the impact?

Which impact?

For doing the MLP, the tax implication.

We really didn't, what we said is that we want to avoid any specific conversation about the MLP. Clearly the tax is a function of a number of things, including how much of the money is actually distributed up and so I don't think it's a conversation we want to get in today given where we are with the filing.

Okay just a general question as it relates to the MLP market as a whole, we've seen some energy MLP deals either get pulled or the market itself not being as great for the MLP. I just want to get your thoughts as far as the timing. You guys just recently came out and we've actually had some other energy people pull back or delay MLPs, so I just kind of want to get your thoughts as far as that goes. Obviously you're very unique and obviously the fertilizer industry is strong, but the MLP market has been a little tougher here. So can you comment on that?

The only thing we can comment is we went first with our eyes open, realizing we filed just two weeks ago tomorrow, we know that our timing will be directly tied to the review period for the SEC. But the only other thing I could say is that when we filed our CVR Energy prospectus with our IPO we clearly delineated pretty much the plans that we had, now we're simply executing on them. I don't know if that helps you or not, but there's not a whole lot else I can say.

No, no, I know. But there wasn't a specific -- I remember on the road show you talked about doing an MLP and I just didn't know if there was some sort of set parameters as far as when you had to file, since you mentioned it, and that was the reason for filing now, or was just the advice that you got was "We think that you would do okay despite the market" type of situation. That's all I'm trying to get.

Again at the time of the road show we couldn't make any promises as to when we thought we would roll it out. I think what we did say is we would use our best efforts to get it out the door at the earliest possible time, we went public in late October and here we are, and obviously it takes a little while to put a prospectus together.

Got you, okay.

We've been a little busy.

Got you. And then one, I'm sorry, just one final question. As far as, you are delivering on your plan, I'm just trying to gauge, trying to think back to the road show, what the next steps for growth are for CVR, corporate CVR.

Excluding the, the only comment that we would make on the fertilizer is that the UAN expansion, which is designed to convert our net ammonia to additional volumes of higher priced, higher margin UAN, is in progress. The rest of that I will stay away from the fertilizer. On the refining side, we are working with a major engineering firm and have gotten pretty high behind a series of studies to scope and cost and give us the economic benefits of two or three different further expansions of the Coffeyville refinery. Our goal there is nominally to, well it's not nominally, it's to increase the amount of heavy sour crude that we are processing. We have taken 25,000 barrels a day of space on the Keystone Pipeline that is scheduled to come down into Cushing from Canada in late 2010 I believe is the timeframe. We need to find some place to put that crude, and that's our goal right now, is to expand the refinery. We will only do it if it is accretional to the shareholders and we are working diligently to make sure what we spend our money on is the best project for our facility.

And are you seeing what other folks in the industry are seeing, as far as a lot of cost creep, and obviously labor is tight, when you're talking to your contractors?

Oh yes, we've already seen that. The fact that we've gone through a $500 million plus expansion program at the refinery, the escalation of equipment and labor has been nothing short of phenomenal, it's really high. But we do factor that in. Having just gone through our own program, we're very cautious. As we look at sensitivities on any of the projects we do, one of the sensitivities is increasing costs. It makes it more difficult to find viable projects, but given our location, where we're at in the mid continent, where we tend to get a premium for our products, our proximity to Cushing Oklahoma, when the wave of Canadian crude washes over Cushing it will have passed over Coffeyville on its way down there, and that's our goal.

If we can run more volumes, higher volumes of more highly discounted crude, even if we don't significantly increase overall rates, it could be an attractive project.

Got you; great. Thank you.

Our next question is from Aaron [Edelheit] with Sabre Value Management. Please go ahead with your question.

Yes, I have a question about the relationship with natural gas and fertilizer prices. And I'm curious what your thoughts are considering that natural gas has been creeping up and that you guys have a competitive advantage due to how you produce your fertilizer. Is there a point at which, either natural gas starts, really start -- if it goes up more, really starts pushing fertilizer? Or production comes off line? I'm wondering if you could give kind of an outlook if natural gas were to go to $15.00 or $16.00 or $17.00, if there's either some benefit to you. Because, the last year or so it's been more demand-driven than natural gas driven in terms of fertilizer prices. I'm just curious what your thoughts are.

Well it's kind of interesting that you picked the $15.00 to $17.00 range because several pundits are arguing that, with crude oil above $100.00, natural gas should be in that range. You might even infer that from LPG prices and the like.

Certainly, if natural gas goes to $16.00 or $15.00 the cost to produce fertilizer will go up substantially, but not for us. It will actually serve to put a larger floor underneath us as we move forward.

Part of the other thing that you have to look at is that the price of corn has gone from $2.00 to $2.50 a bush two years ago to $5.00 to $5.50 a bushel and maybe even higher going forward. So, while corn has run, there is room for the farmers, for the producers of the corn, to actually pay market price for fertilizer and still make a healthy profit.

Jack is absolutely right. In the last two years, we just have not seen the connection in natural gas and fertilizer prices. They've disconnected mainly because of some of the things we've talked about in terms of global demand.

So, it would put a different floor on price but I don't think it would phenomenally change the price because it's not driven by natural gas and it hasn't been for the last two to two-and-a-half years.

Do you think that there's any level at which some of your competitors in the fertilizer side experience pain or an amount of pain that would cause them problems? Or do you think that, due to the Ag market and how strong it is, that they would be able to push through prices?

You know, right now, if you were to assume that natural gas was $15.00, the cost to produce a ton of ammonia is just slightly over $500.00, plus some operating expense, $20.00 or $25.00 perhaps or maybe it's even in there; so, somewhere between $500.00 and $525.00 a ton.

Prices for pumped ammonia are over $600.00 a ton so, even at $15.00 natural gas, our competitors in the fertilizer business would not be happy but they would still be profitable if today's prices hold.

Got you. You know, it's just really interesting because natural gas has historically been anywhere from four to six to one to oil, in terms of a ratio. But the last two or three years have completely blown that away. If that ever gets closer together, it'll just be interesting to see what happens.

You're right.

Thank you very much.

Our next question is from Milan Gupta with South Point Capital. Please go ahead with your question.

Hey guys, you might've touched on this but I was just curious why fertilizer production was down just year-over-year.

Well there are two reasons. Stan pointed it out. One was we had a turnaround; sorry, not a turnaround; a flood. And the other was we had an expander come down on our UAN plan.

And secondly, we were using hydrogen from the fertilizer plant and selling the hydrogen direct to the refinery. And now, with the CCR, those volumes will be reduced.

Yes. If you normalize all of the hydrogen that went to the refinery, between '06 and '07, the '06 ammonia was 395,000. The '07 ammonia was 387,000, which is very close to Jack's point that the delta would have been the flood.

The real delta is the repair work we had to do on the expander for UAN, which we have solved that. We now have two; we have one spare expander and we have another one on order. So that will not be a recurring event.

Okay, so you were still -- the production for the fertilizer was still impacted in the fourth quarter?

Yes. We look not just at ammonia at UAN production. We look at hydrogen because that's the real driver, how much hydrogen you're getting out of the gas so far. And, say, the 15 days that we were down for the flood, the hydrogen production was pretty much equivalent, year-over-year.

I got you. And then one other thing is we're trying to track, sort of, the earnings of the fertilizer business. If I look to just -- is there a reason why your UAN price would differ materially from the U.S. Gulf Coast price? Or what's the right way to think of the puts and takes there?

Well, we sell forward and Jack talked to this a little bit. We sell forward our UAN production because most of the storage is at the dealer level. And we sell strongly through the time period of July through September then intermediately, beyond that. So, we will have a book of orders that stretches out four or five months. And then we'll slow down to, or come in within about three months.

But, on a spot basis, we should equate right with the Gulf, whatever the Gulf is on the day we take the order, we'll be there. And all our projections are that the prices continue to go up for '08. We're looking at a very good '08.

Jack or Tim, would you want to expand on that?

Well, the only thing I'll say is because we're selling forward and into a rising market, it looks like we're netting back lower numbers than the market. But at the time we took the order, we took consistently historically high priced orders all year long. It's just that the historically high prices keep going higher.

Got you; so what's the right way to think of in terms of the lag? Like, should you track the (inaudible)....

Six months.

...closer by - six months? Okay.

Four to six months.

Four to six months, yes.

Okay. That's great; thanks.

(OPERATOR INSTRUCTIONS).

Your next question is from Vijay [Prasaad] with Lion Capital Management. Please go ahead with your question.

Hi; thanks for the call. Just a quick question on the gain and loss on derivatives; it's a negative -30.1 in Q4. I was wondering what the total unrealized portion was. You may have touched on this but I just want to make sure.

The unrealized loss on the swap for Q4; this is ignoring any tax impact was --- hold on just a second -- about $4.9 million.

Positive?

No; it was a loss.

Okay. And is that the only unrealized portion? Or do you have any on other hedges as well?

We also have an unrealized interest rate position that we lost about $4.2 million on. We have about, I think it's 325 or 365. I can't remember the number off the top of my head, of interest rate fixed. It's slightly over 4% on LIBOR.

Okay so it's negative -4.2% on the interest rate?

Yes.

And negative -4.9% on the hedges, the cash flow hedges? Okay. So, that's the sum total of the unrealized portions?

Yes.

I guess the reason I'm asking is I mean, one of the main add backs, I guess, to EBITDA, right?

The only other thing that's in the add back that you see, though, is the tax affected swap. We don't add back for the interest rate.

Okay. Okay; thanks.

Your next question is from Vance Shaw with Credit Suisse. Please go ahead with your question.

Hi, yes. Good afternoon. I'm with the Credit Suisse on the buy side. I just have a couple of balance sheet questions since I'm a lender to the company.

Could you guys give me any idea of what your availability was in your revolver?

As of today it's about $54 million.

Okay and there's about, I see there's $500 million, some odd, of long-term debt. On the balance sheet would that all be...?

That's not long-term; that's total debt. That's about $488 million of long-term debt plus the revolver balance.

Oh, I see. I got you. Okay, thanks. And, now, if we go back in history a bit, there was, I guess, Jay Allen had a loan out to you guys during the flood situation. Has that all been paid off?

No. Tim mentioned it briefly; we have $124 million delayed payment that we will make in August.

That shows up in the current portion of payable to swap counter party.

I got you; I understand. Okay and anything on the ratings front from Standard & Poor's these days?

Just what they've issued publicly.

Okay, which was they're basically keeping you where they were?

Yes.

Okay and I guess, if that gets knocked up to, what? B1 or B2 then the margin on the loan would go down?

We've already achieved most of the margin benefit on the loan. There's not a lot of upside left.

Okay. I'm sorry; are you guys still at [L325] on that?

No; no. We already received a step down to 275.

275, okay. Thanks very much.

At this time there are no further questions in queue. I'd like to turn the call back over to management for closing remarks.

Well, this is Jack Lipinski. I thank you all for joining us. It's a pleasure, seriously. We're excited about the company. We have lots of opportunities; we've got a real hard working team and we actually enjoy getting up in the morning to come to work.

So you folks are the ones that are making it happen for us and we thank you. So, with that I will turn it over to Stirling.

Okay. Again, thank you. I'll reiterate everyone's comments. I appreciate your being here and all the questions and so forth. And we'll speak with you in the near future. Thanks again; goodbye.

Thank you all. Goodbye.

This concludes today's teleconference. You may disconnect your lines at this time and thank you for your participation.