CVR Energy, Inc. (CVI) Q3 2019 Earnings Report, Transcript and Summary

Greetings, and welcome to the CVR Energy, Inc. Third Quarter 2019 Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Jay Finks, Vice President of Finance and Treasurer. Thank you, you may begin.

Thank you, Michelle. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy Third Quarter 2019 Earnings Call. With me today are Dave Lamp, our Chief Executive Officer; Tracy Jackson, our Chief Financial Officer; and other members of management. Prior to discussing our 2019 third quarter results, let me remind you that this conference call may contain forward-looking statements as that term is defined under federal securities laws. For this purpose, any statements made during this call that are not statements of historical facts may be deemed to be forward-looking statements. Without limiting the foregoing, the words outlook, believes, anticipates, plans, expects and similar expressions are intended to identify forward-looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings results. As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent required by law. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliation to the most directly comparable GAAP financial measures are included in our 2019 third quarter earnings release that we filed with the SEC. With that said, I'll turn the call over to Dave.

Thank you, Jay. Good afternoon, everyone, and thank you for joining our earnings call. Hopefully, you had an opportunity to listen to the CVR Partners earnings call earlier today. Yesterday, we reported third quarter consolidated net income of $104 million and diluted earnings per share of $1.18. EBITDA for the quarter was $235 million. Despite tighter crack spreads and crude differentials in the third quarter this year, we generated strong quarterly results through safe, reliable operations, improved capture rates, higher throughput volumes and increased fertilizer sales and pricing. We also announced a $0.05 increase in our quarterly dividend to $0.80 per share. The third quarter dividend will be paid on November 12 to stockholders of record as of the close of market on November 4. With this increase, our current annualized dividend of $3.20 per share represents an industry-leading dividend yield of over 7% based on yesterday's closing price. For our Petroleum segment, both plants ran well with no material downtime during the quarter. Combined total throughput for the quarter of 2019 was approximately 222,000 barrels per day as compared to 221,000 barrels per day in the third quarter of '18. The Group 3 2-1-1 crack spread averaged $18.30 per barrel in the third quarter of '19 as compared to $19.88 in the third quarter of '18. Domestic crude differentials have tightened recently, primarily due to the startup and line fill of new pipelines from West Texas to the Gulf Coast. The Brent-TI differential averaged $5.63 per barrel in the third quarter of '19 as compared to $6.33 per barrel in the third quarter of '18. The Midland Cushing differential narrowed to $0.26 per barrel in the quarter as compared to $14.33 per barrel in the third quarter of '18. The WCS differential to WTI was $12.59 per barrel as compared to $27.76 per barrel in the same period last year. The tightening of the WCS differential is largely a result of continued production curtailments imposed by the Alberta government. Light product yield for the quarter was 98% on crude oil processed. Our distillate yield as a percentage of total crude oil throughputs was 45% in the third quarter of '19, in line with prior year period. Our distillate yield consistently ranks as one of the highest among the U.S. independent refiners. In total, we gathered approximately 127,000 barrels per day of crude oil during the third quarter of '19 as compared to 113,000 barrels in the same period last year. Our gathering volumes continue to increase throughout the quarter, with September volumes at 137,000 barrels per day. As we continue to shift our slate for crude oils gathered in our own backyard, we have increased our SCOOP gathering runs by over 20% relative to the third quarter of '18, while reducing our gathering activities in other nonstrategic regions as well as our purchases of Cushing common crude oil. During the third quarter, the Fertilizer segment had strong reliable operations at both facilities. Coffeyville's ammonia unit operated at 98% utilization in the quarter as compared to 94% in the third quarter of '18. At East Dubuque, the ammonia unit operated at 98% utilization leading up to the turnaround as compared to 100% in the prior year period. The turnaround at East Dubuque was completed in October and is now coming back up to full production. Year-over-year UAN sales volume, higher prices for both UAN and ammonia and lower natural gas prices resulted in Fertilizer's positive EBITDA contribution to CVR's consolidated financial results. The Board of Directors of the CVR Partners' general partner declared a third quarter '19 distribution of $0.07 per common unit, which will be paid on November 12 to unitholders of record at the close of market on November 4. As CVR Energy owns approximately 34% of CVR Partners common units, we will receive a proportionate amount cash distribution of approximately $3 million. Now let me turn the call over to Tracy to discuss additional financial highlights.

Thank you, Dave, and good afternoon, everyone. As Dave mentioned, for the third quarter of 2019, we reported consolidated net income of $104 million and diluted earnings per share of $1.18. This compares to net income of $110 million and diluted earnings per share of $0.85 for the third quarter of 2018. The effective tax rate for the third quarter of 2019 was 25% compared to 23% for the prior year period. The improvement in diluted earnings per share and the increase in our effective tax rate were both due primarily to the decrease in noncontrolling interest as a result of the first quarter equity transaction. We continue to expect that our full year 2019 effective tax rate will be between 20% and 25%. The Petroleum segment's EBITDA for the third quarter 2019 was $228 million compared to $219 million in the same period in 2018. The increase in EBITDA year-over-year was driven by higher capture rates and increased throughput volume. In the third quarter 2019, our Petroleum segment's refining margin, excluding inventory valuation impact, was $16.37 per total throughput barrel compared to $15.57 in the same quarter of 2018. The decline in crude oil flat price through the quarter generated a negative inventory valuation impact of $0.03 per barrel during the third quarter of 2019. This compares to a $0.12 per barrel positive impact during the same period last year. The capture rate, excluding the inventory valuation impact, was 89% in the third quarter of 2019 as compared to 78% in the third quarter of 2018. Total derivative gains for the third quarter of 2019 totaled $18 million, which includes unrealized gains of $14 million associated with open commodity derivative instruments and open purchases of Canadian crude oil that are scheduled for future delivery. In the third quarter 2018, we had total derivative gains of $5 million. RINs expense in the third quarter of 2019 declined by $22 million compared to the same period last year. The year-over-year decline in RINs expense was driven by a combination of lower RINs prices and a reduction in our prior year renewable volume obligation. Based on recent market prices of RINs and current production plans, we now estimate that our RINs expense will be approximately $40 million to $50 million in 2019. The Petroleum segment's direct operating expenses were $4.46 per barrel of total throughput in the third quarter of 2019 as compared to $4.13 per barrel in the prior year period. The increase was primarily associated with increased labor or materials cost offset by lower expenses for utilities and outside services. For the third quarter of 2019, the Fertilizer segment reported an operating loss of $8 million and a net loss of $23 million or $0.20 per common unit. This is compared to third quarter of 2018 operating income of $3 million and a net loss of $13 million or $0.12 per common unit. Adjusted EBITDA was $18 million in the third quarter of 2019 compared to $19 million for the prior year period. The slight year-over-year decrease in adjusted EBITDA was primarily due to higher operating costs and higher pet coke prices. Total consolidated capital spending for the third quarter of 2019 was $34 million, which included $27 million from the Petroleum segment and $7 million from the Fertilizer segment. Of this total, environmental and maintenance capital spending comprised $31 million, including $25 million in the Petroleum segment and $6 million in the Fertilizer segment. We now estimate the total consolidated capital spending for 2019 to be approximately $145 million to $165 million, of which approximately $120 million to $135 million is environmental and maintenance capital. This excludes planned turnaround spending, which we estimate to be approximately $50 million to $55 million for the year. The approximate $15 million reduction in our 2019 capital spending plan is the result of a shift in timing for certain capital projects into subsequent years. Our cash position remains strong as we ended the quarter with cash of approximately $692 million on a consolidated basis, which includes $84 million in the Fertilizer segment. We continue to feel confident in our strong balance sheet and liquidity position. Looking ahead, for our Petroleum segment, we estimate total throughput for the fourth quarter of 2019 to be approximately 205,000 to 220,000 barrels per day. We expect total direct operating expenses for the fourth quarter to be approximately $90 million to $100 million and total capital spending to range between $50 million and $60 million. For the Fertilizer segment, we estimate our ammonia utilization rate to be between 95% and 100%, excluding the impact of planned turnaround. We expect direct operating expenses to be approximately $40 million to $45 million, excluding inventory and turnaround impacts and total capital spending to be between $8 million and $10 million. With that, Dave, I'll turn the call back to you.

Thanks, Tracy. In summary, we are proud of our strong results in the third quarter of '19. Our mission continues to be a top tier North American petroleum, refining and fertilizer company as measured by safe, reliable operations, superior financial performance and profitable growth. Before discussing our market outlook, I'd like to provide an update on the formal bank process we announced in May. We acknowledge that our premium valuation relative to our peers, to many of our peers, resulted in a wide bid-ask spread, and therefore, that bank process is now concluded. However, we continue to evaluate various revenue diversification and value creation opportunities. Along with the previous mentioned 7% increase in the dividend, the Board has authorized a 4-year stock repurchase program of up to $300 million. We will consider opportunistically repurchasing our shares as one potential way to return excess cash to shareholders over time. I would like to reiterate that we continue to believe the best use of available cash is in a stable and growing dividend and funding high-return capital projects, but this repurchase authorization will provide us with additional financial flexibility should the opportunity arise. We remain focused on efforts to improve our business through increasing shale crude sourcing and optionality, improving our capture rates and exploring ways to diversify into other high-valued business segments. Looking at the remainder of '19 and into '20, we continue to have a constructive look -- outlook, driven by a range of positive market fundamentals that we see. First, low crude prices and low unemployment are positive for U.S. refined products demand. Second, continued low natural gas prices benefit both our refining and Fertilizer businesses. Third, gasoline demand remains strong with the latest data showing year-to-date vehicle miles traveled in the U.S. up by almost 1% compared to last year. Fourth, refined product inventories remain in check and are currently at or below 5-year averages. Five, U.S. petroleum exports remain strong. Year-to-date gasoline and distillate exports have averaged over 2 million barrels a day, and crude oil exports have been above 3 million barrels per day throughout much of the year. Six, domestic shale, crude and specifically, light crude production continues to increase. Recent government data shows that year-over-year growth in the crude oil production for the major shale oil basins over -- of over 900,000 barrels per day. Light WTL volumes are increasing as well, and we believe these barrels should sell at a discount to WTI. Seven, although RIN prices have been volatile, they currently remain relatively low. The EPA, again, granted 31 small refinery exemptions for the '18 compliant share, and we believe that all requires continuing -- continued granting of these exemptions in the future. Eight, IMO implementation remains on track for January 1, and we continue to believe these new standards represent a tailwind for the refining industry in general. IMO impacts are already beginning to show up in the market evidenced by the recent widening of high sulfur fuel discounts. Part of the recent increase in shipping rates may also be attributed to IMO 2020, and we view this as a positive for the Brent-TI spread going forward. And finally, Tier 3 gasoline specifications changes will also be fully implemented in -- by January 1. This likely represents another tailwind for the refining industries for those that are prepared. We believe that the market still does not fully understand or appreciate the potential impacts of IMO 2020 Tier 3 gasoline and the continued growth in domestic shale oil crude production. We are well positioned in regard to all these market forces, and most of the capital projects we are developing will further increase our ability to make premium gasoline, increase our liquid yields and expand our feedstock optionality. The Coffeyville crude optionality project, if approved, is intended to increase our capacity for processing natural gasoline to 10,000 barrels per day. Natural gasoline spreads to regular subgrade have averaged over $0.60 a gallon this year and are expected to widen further with the implementation of Tier 3 gasoline specs. Schedule A engineering design work and cost estimating are almost complete. The new C5/C6 isom at Wynnewood is also in Schedule A engineering and cost estimating. If approved, this project should improve our capture rate and our liquid volume yield. And as we continue to evaluate the replacement of HF acid catalyst in our Wynnewood alkylation, this project is expected to increase production of alkylate at Wynnewood and therefore, the production in premium gasoline. We believe all these projects are attractive and should generate returns of 30% or greater. Engineering work continues, and we expect to have these projects defined and ready for Board approval by the end of the fourth quarter. Looking at the fourth quarter of 2019, quarter-to-date metrics are as follows: Group 3 cracks have averaged $20.70 per barrel, with the Brent-TI spread at $5.63 and the Midland Cushing differential at $0.79 per barrel over WTI. The WTL differential has averaged $0.08 over Cushing WTI. Ethanol RINs have averaged $0.19 consistent with the third quarter average, and biodiesel RINs are at $0.56 compared to $0.45 last quarter. With that, Michelle, we are ready for questions.

[Operator Instructions]. Our first question comes from the line of Neil Mehta with Goldman Sachs.

I guess the first question -- and congrats on a good quarter here. I guess first question, as it relates to diversification, can you kind of walk us through potential areas with which you might look to expand or broaden out business? The one that comes to mind is retail, where you guys don't have a presence right now. Could you talk about what could fit within the portfolio?

Sure, Neil, and thanks for the compliments on the quarter. The things that probably appeal to us most is diversification of our earning streams from somewhere outside of the group. PADD IV would be of interest to us. Probably not PADD III or PADD I or PADD V, but specifically PADD IV, just because we look for those niche-type opportunities. And then secondly, on RINs, I think, our strategy around retail is really around RINs mitigation. We are still the poster child for RIN -- high RIN prices, and we recognize it. We've taken steps to increase our internal blending, but we still have to either get into the wholesale side of business or retail to really -- to make a dent in that whole process. Of course, with our a higher yield of distillate, it makes it difficult because that doesn't really lend itself to -- via our marketing channels to really doing much about it. But those all remain on the table, and we continue to look at it.

David, on your comments on PADD IV, why do you think that's the best fit for your footprint? And there has been talk of some PADD IV assets hitting the market. Any comments that you can provide there would be interesting.

Yes. I think it's more -- we're an in-land refiner and we like that dislocation from the main liquidity points and think that's a value-added stream for us that we would like to continue that kind of differentiation.

Okay. And then just can you remind us where you stand with all the quick-hit projects that you are working on to improve the refining system? What has come on? What is to come on? And how do we think about allocating capital to those investments to once again enhance the refining system?

Well, the one that we recently completed was the Benfree relocation in front of the reformer rather than behind the reformer, and that is fully implemented in service. And largely, a lot of -- some of the improvements in capture rate you're seeing is because of that project. We also replaced catalyst at both reformers at both refineries. And that has also -- I don't know if you follow the premium spreads in the group, but in the third quarter, they averaged $0.35 over subgrade. And that -- that's a lot of what improved our capture rate in the past. Some of the others are longer term projects, the three I mentioned in the prepared remarks were -- are all in that 2022 -- 2021, '22 range. So they'll take some time to develop.

Our next question comes from the line of Paul Cheng with Scotia Howard Weil.

Dave, maybe this is for Tracy. Tracy, how much is the actual small refinery exemption benefit that you recorded in the quarter?

We do not confirm that we received an exemption simply that we received a reduction in our RVO obligation for prior year.

Okay. Can you tell us then that what is that amount? Now up to '22, you said $19 million, '20, $18 million, and any kind of range that you can provide?

I would point you to the prepared remarks and the decrease over prior year as directionally what you should be considering, but I can't confirm that we received any exemption.

And Dave, just curious that, I mean, when you're looking at potential acquisition, I mean, how much is the leverage rate -- leverage that you want -- you would be willing to put on for the right asset?

I didn't understand your question, Paul.

So if you do go for an acquisition for a refinery, how much debt you're willing to put on in order to complete the transaction? What is the net ratio, yes, in your balance sheet, how much leverage that you're willing to put on? What's the maximum?

I don't think we get outside the industry average, but right now, our balance sheet is very strong, we're well on cash. So we would put the appropriate amount on there or take other actions to raise capital to do such a thing.

Is that a ratio that like net debt-to-EBITDA or net debt to capital ratio or any target?

We don't have a target there, Paul, at all that we're trying to hit or anything. Right now, we're real low compared to our peers, and we have capacity to add.

And when you're looking at the current environment on the refinery sales a big part , do you think that there's a pretty wide discrepancy between what people maybe asking and what is the potential buyer willing to pay on the individual assets?

In our case, I think the bid-ask was extremely wide and part of it was the industry. A part of it, frankly, there aren't that many consolidators out there to even compete. I would make a comment that the E&P companies I don't think are long cash in Any way, shape, or form at $55 crude or $50 crude. And therefore, you're left with refiners that -- there just aren't that many out there that have the wherewithal to do it. And again, in our case, we're looking for diversification of EBITDA, just adding more Group 3 type assets really doesn't move the deal for us. We're exposed to the same market parameters. And what we need as a company is the diversification of that EBITDA source.

And if we're looking at to date, the Midland price is about a $1 higher than Cushing. So does it still make economic sense for you guys to run the Midland crude under that scenario? And if you don't that, do you have any kind of take-or-pay or minimum volume fee you have to pay?

No. We're just on historical space on basin pipeline. If we don't use it, we tend to -- assuming that's proportion, we would lose historical space. But that's not necessarily the case. In our case, our strategy is really all around gathering crudes around in our backyard and that for the most part is the SCOOP and the STACK, and there is -- we have proprietary lines as well as public lines that we have pretty good long runway to go there. Our purchases of Cushing common are down substantially, and we have the flexibility to bring Midland in if it's profitable and then don't bring it in, if it isn't. If you bring attention to the WTL barrel, which is the light version of WTI and that volume is growing rapidly, and we have the ability to process that material also for the WTI.

Sorry. How much is the WTI line you could run, given the way economy...

We're still determining that, but if -- it's a value-added crude to us over WTI. It's just so new to the market, Paul, we just don't have enough data yet.

Okay. That's great. Final question. For UAN, OpEx $48 million in the quarter seems high, but that has been high for the last 2 quarter. I don't know, is it mainly because of the turnaround. What will be a reasonable runway going forward?

Paul, I think you can look forward to see something between $40 million and $50 million. It was higher in the quarter due to our turnaround that was going on at the East Dubuque facility.

So Tracy, we are not going to see them go back to because a couple years ago that you would be in some sub-$40 million, now you're in $35 million, $37 million. So we're not going to go back down to that kind of level?

Remember, the impacts of inventory changes also impact their OpEX expense on a quarterly basis, so we have that occurring in this past third quarter. So that will, depending on whether we're building or drawing inventory, continue to have an impact. And then if you listened to the call, I referenced back to the script, Mr. Pytosh indicated that they're going to make investments in debottlenecking and reliability projects going forward, which to the extent our maintenance projects will be expensed as we complete them.

Okay. So that means that we're not going to below $40 million. So $40 million to $50 million is the new range that we should assume?

Depends on what happens in inventory, Paul. So...

Right.

Our next question comes from the line of Prashant Rao with Citigroup.

First one's on SCOOP/STACK gathering, just kind of a macro question and how do you may fit or maybe are not as exposed to some of the negative headwinds in SCOOP/STACK, specifically, the rig count's down pretty dramatically year-to-date, and I get that that's due to the fact that there's more gas NGL price sensitivity. But we've been getting some questions in our upstream about productivity -- in our upstream coverage on productivity in some of the areas and some fears from investors that the production rolling over for some of the operators there next year. So I was wondering if you can maybe comment to that because the macro seems to be incrementally negative, but you guys have been able to increase your gathering there and get some distillate-rich barrel? So just wanted to get some thoughts and color on how to frame that up from here.

Well, I think, the way to answer that is that we're aligned with the large producers out there, and we pretty much take all their production, and they -- you've heard of the driftwood formation, and they've been very productive out of that, and we go right with them. So our pipeline connected basically to them. So that's how we've grown it. Yes, I think, the rig count is down, DUCs are down, but production seems to still grow in that region on these really productive plays.

Okay. And do you have a good confidence that kind of you at least won't be affected in case some production rolls over and feels -- sounds like what you're saying is they'll probably be smaller operators, not the larger guys that you're connected with, is that fair?

That's correct. And these guys are -- we get their projections going forward, and there's still seeing up and to the right.

Okay. Makes sense. A follow-up question related to the buyback. Just curious how you would go about that, what your options may be open market, looking at NCIB? Or would you considered doing a block given -- I'm asking the question specifically because of the shareholder concentration in your base. I just wanted to get a sense of how that might play out, what you're keeping open on the table here?

Well, I think it's a four year authorization, and I think we made it abundantly clear that we'd only do it when the opportunistic opportunity shows up and that implies a -- this is a cyclic business and it rolls. Sometimes, when it rolls low, we'd probably be buyers. How we exactly go about it is we really haven't disclosed that and probably won't until that time comes, if it comes.

[Operator Instructions]. Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt & Company.

And Dave, any update on how you're thinking about UAN as part of the portfolio, whether that makes sense long term or whether you might even, I guess, add to your exposure to UAN here?

Well, that will certainly be a diversification of our EBITDA, but -- and where the stock's currently trading and what we think the forward curve is. It could be attractive, although we don't view it as highly accretive at this point. I think we'll keep an eye on it. We'll look at it. Our ownership is only 34% of that. So it's a big nut to take it all the way to underneath the CVI umbrella. But we also are very cognizant of what's happening with variable distribution MLPs and the effect on that. So we continue to watch it, Matt.

Sounds good. And then you mentioned reduced gathering. What's the good EBITDA number for your gathering activities? Is it still around $70 million or so? And sorry, can you repeat what was the gathered volumes in the quarter?

Are you talking about MLP-able, logistical-type assets?

Correct.

It has gone up since our volumes have gone up. In fact, our Red River Pipeline, we bought back in late '17, is basically full and that we're delivering barrels from the Wynnewood area to Cushing and then on to our refinery in Coffeyville. So I think, it's gone up some. We quoted $70 million before, it's probably more in the $80 million range, I'm going to guess. And we're looking at other opportunities for assets like that, that we can roll into it. We have no plans to do any kind of logistical MLP. We just don't have the scale for it.

Got it. And what were your gathered volumes in the quarter?

127,000 barrels per day.

There are no further questions at this time. I'd like to turn the call back over to management for any closing remarks.

Okay. Again, thank you all for your interest in CVR Energy. Additionally, we'd like to thank all our employees for their hard work and commitment towards safe, reliable and environmentally responsible operations. We look forward to reviewing our fourth quarter 2019 results during our next earnings call. Thank you.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.