Good day, and welcome to the Par Pacific Investor Conference Call. [Operator Instructions]
Please note, this event is being recorded. I would now like to turn the conference over to Ashimi Patel, Director of Investor Relations. Please go ahead.
Thank you, Betsy. Welcome to Par Pacific's investor conference call. Joining me today are William Pate, President and Chief Executive Officer; and Will Monteleone, EVP and Chief Financial Officer.
Before we begin, note that our comments today may include forward-looking statements. Any forward-looking statements are subject to change and are not guarantees of future performance or events. They are subject to risks and uncertainties, and actual results may differ materially from these forward-looking statements. Accordingly, investors should not place undue reliance on forward-looking statements, and we disclaim any obligation to update or revise them. I refer you to our investor presentation on our website and to our filings with the SEC for non-GAAP reconciliations and additional information. We are sharing user controlled slides via the webcast for today's call, and the presentation can also be found on our website under the Investors tab.
I'll now turn the call over to our President and Chief Executive Officer, William Pate.
Thank you, Ashimi. As noted on the second slide, we were pleased to announce yesterday the $310 million acquisition of the ExxonMobil Billings' 63,000 barrel per day refinery and the associated logistics system. We also signed a long-term ExxonMobil branded fuels marketing arrangement to supply approximately 300 regional locations. The Billings operation will add significant scale to our business, increasing total throughput capacity to 218,000 barrels per day and enhancing our fully integrated downstream network in the Upper Rockies and Pacific Northwest.
As noted on Slide 3, this acquisition brings many strategic benefits. After the transaction, we expect to have among the highest exposures of any public refiner to discounted heavy Canadian crude. Given our existing footprint, the commercial opportunities and expected cost savings, we expect significant synergies in excess of $30 million per year.
With our share price trading at less than 4x current year earnings, it's difficult to complete an accretive transaction, but with our current cash position, we expect this acquisition to be immediately accretive on both the free cash flow and earnings per share basis.
The Billings operations are a perfect fit with our strategy of being an owner-operator, of market-leading downstream systems in niche markets. Prior to the pandemic, we completed a string of successful acquisitions beginning with our Hawaii refining and retail businesses. We then added Mainland exposure to our portfolio and began building out a network in PADDs IV and V through our Wyoming and Washington refining and Northwest Retail acquisitions. These investments have generated strong returns and have built the foundation for the next phase of our growth.
I'll now turn the call over to Will to review the transaction and financial highlights.
Thank you, Bill. Back to Slide 2, we expect to fund the $310 million purchase price with cash on hand and existing credit lines based on liquidity of approximately $495 million as of September 30. This liquidity includes approximately $409 million of cash on hand, and we continue to generate significant cash each month in the current market environment. We expect to fund the hydrocarbon inventory with a new working capital facility.
On Slide 4, we've laid out our expectations for pro forma mid-cycle earnings uplift. We believe mid-cycle adjusted EBITDA for our existing operations to be approximately $300 million. We expect annual billings mid-cycle adjusted EBITDA of $140 million, including synergies, implying a 2.1x adjusted EBITDA multiple. On a combined basis, we expect pro forma mid-cycle adjusted EBITDA of $440 million and approximately $95 million in normalized maintenance capital and turnaround outlays. We anticipate strong free cash flow generation from the combined company.
I want to note the $35 million of additional forecasted logistics adjusted EBITDA. As previously stated, our gross debt target is based upon a 3 to 4x adjusted EBITDA from our logistics and retail operations. With this incremental contribution, we are comfortable with gross debt in the range of $500 million to $600 million. Gross debt as of 9/30 was [ $519 ] million. Based on our current outlook, we anticipate being at the bottom of our targeted range upon closing of this acquisition in the second quarter of 2023.
Turning to the refining highlights on Slide 5. The 63,000 barrel per day refinery is highly complex and processes a slate of discounted Western Canadian and Rocky Mountain crude oils, including approximately 49% Western Canadian heavy crudes. Refineries production yield includes approximately 48% gasoline and 28% distillate with the ability to increase distillate production up to 31%. The transaction also includes a 65% interest in an adjacent cogeneration facility. We are evaluating renewable fuels conversion opportunities to supplement the refinery's conventional fuels production.
Moving to the logistics highlights on Slide 6. The acquisition includes an expansive network, crude and product midstream assets across the Upper Rockies and Pacific Northwest, including the wholly-owned 55,000 barrel per day Silvertip crude oil pipeline, a 40% interest in the 750-mile Yellowstone clean products pipeline and 7 refined product terminals. This logistics network dovetails perfectly with our strategy of ensuring we can fully distribute our products to end users. The Yellowstone products pipeline has long been a critical artery for serving the Montana and Washington markets. 7 connected terminals broaden our reach within the region.
Now to Slide 7. We have a long-term arrangement to supply Exxon branded locations in the PADD IV and PADD V regions, traditionally served by the Billings refinery. As a result of this arrangement, more than 75% of our clean products production will be under contract Exxon branded or Par Retail operated locations. We're excited to add the strength of the Exxon brand to our portfolio.
I'll now turn it back to Bill.
Thank you, Will. We can't envision a better fit to our current asset base than the Billings operation. This acquisition significantly expands our mainland refining capacity. The Yellowstone pipeline and Washington terminals allow us to move clean products into Washington to leverage our market position in that region. We also intend to work with the Billings team to develop capital projects that improve reliability and increase production, and we hope to supplement conventional production with renewable feedstocks.
In closing, I would like to welcome the dedicated and highly skilled Billings employees to the Par Pacific team. My colleagues and I were able to spend some time with the team on-site yesterday, and we're confident that there are even more opportunities for growth than we realized as we work with the local team to unlock the site's potential. We look forward to expanding our companies and capabilities together.
This concludes our prepared remarks. Operator, I'll turn it back to you for Q&A.
[Operator Instructions] First question today comes from Carly Davenport with Goldman Sachs.
Wanted to just start on the mid-cycle EBITDA view. Can you just talk about kind of the assumptions driving that and perhaps, what you think might be drivers that could cause that to surprise to the upside or downside?
Yes. Sure, Carly. This is Will. I think first and foremost, we're pacing our numbers assuming annual throughput of about 50,000 barrels per day, which is consistent with historical throughputs in non-turnaround years. And with respect to market conditions, what we've done is, we've really looked over the last 6 years, and we've excluded 2020, and we've excluded 2022 as outliers really in either direction. And you could look at it differently, and it would imply a market environment where the RVO adjusted 3-2-1 Gulf Coast cracks versus ICE Brent would average about $8 per barrel, and Brent versus WTI was about $4 per barrel. So keep in mind, the PADD IV pricing is at a premium to Gulf Coast given transportation constraints, and so that's one of the key drivers to the overall margin contribution and uplift. But I think it ties back to a more, we'll say, mid-cycle or average market environment is the way that we're thinking about these numbers.
And Carly, if I could add to that, as Will referenced, our view of mid-cycle correlates to roughly an $8 per barrel range for the U.S. Gulf Coast RVO adjusted crack. If you look at the current forwards for 2023, it would correlate closer to $14 per barrel.
Got it. Great. And then just kind of stepping back, as you think about the broader business, you've talked historically about wanting to scale the refining business in the PADD IV and V regions, which you're obviously doing with the skill. So when you think about the scale of the business and the mix that you would kind of view as optimal, where do you think this transaction kind of puts you relative to that optimal level?
I think it certainly gives us the scale that we need. It gives us some diversification from a site perspective, and obviously, it's a big transaction for us. It doubles our capacity on the Mainland. So our focus is really going to be integrating the transaction and growing from here and ensuring that we get all the value out of this transaction.
The next question comes from Matthew Blair with Tudor, Pickering, Holt.
Will and Bill, could you -- congrats on the deal. Could you talk about just, I guess, how this came about, provide any background? How long were you talking to Exxon here? And was this a directly negotiated deal or like a competitive auction bid?
We've had -- we've been very clear that this area is an area of interest for us really since we acquired the Wyoming refinery, Matthew. I think you're aware of that. And I don't want to speculate about Exxon's process or their rationale, but we engaged in a conversation with them. And I think that we both decided that, frankly, this asset is a better fit for us than for them, given the scale of their business and overall refining system and given the opportunities for us. And so I think we directly negotiate them a price that met the value where they were willing to part with the asset.
Sounds good. And when was the last major turnarounds? And are there any upcoming major turnarounds that we should be aware of?
Matthew, this facility operates a little differently than our existing sites and that our current facilities, we really conduct plant-wide turnarounds. Given the complexity of the site and the number of units, you have more of a staggered turnaround schedule. And so depending on the unit, you're operating kind of every 3 to 5 years. And again, I think the best way to think about it is, the normalized -- or amortized turnarounds that we're thinking about over every 3 to 5 years is approximately $20 million. And again, so it's going to be lumpy, and we don't think it's appropriate for us to specify precise turnaround schedule at this juncture given we don't control the asset yet, but I think for modeling purposes is the right way to think about it, the amortized turnaround numbers that we've given you.
Sounds good. And then the -- so the logistics EBITDA of $35 million, does that also include the marketing contribution? Or would that be separate?
That's separate, Matthew. And I think we're really probably not going to break out marketing as a separate segment. Again, I know some of our peers do, but ultimately, the logistics earnings stream is a combination of ultimately the Silvertip pipeline crude deliveries, a 40% interest in the Yellowstone products line. And then the terminals across Montana and Washington really providing the base of that logistics earnings profile.
The next question comes from John Royall with JPMorgan.
Congratulations on the deal. If you could talk a little bit about the potential timing of synergies, kind of how that phases in overtime with the $30 million. And then just any color you can provide over some of the various buckets that, that might fall into?
Sure, John. This is Will. So really 3 buckets of synergies as we think about it once just overhead reduction. And again, this is indirect non-Billings type of specific overhead reduction. The second is really commercial and the third is operating synergies. So with respect to the timing, we'd expect to achieve the indirect non-Billings related overhead reductions of approximately $15 million to $20 million within the first year of ownership, and then with the additional kind of $10 million to $15 million to come over the next 2 years. And when you think about the other components, really, it's -- so ultimately, we're looking at commercially a broader footprint across PADD IV and V to enhance our ability to place products in the highest netback markets. And then lastly, we're anticipating working closely with the Billings operating team to continue to improve overall plant reliability and enhance throughputs.
Great. And then can you just talk a little bit more about the opportunity set in renewable fuels? Are you envisioning some kind of coprocessing? And what kind of volumes would you expect there potentially?
John, I think it's still very early, and we certainly want to engage the team in Billings on this, but the facility actually has a 6,000 barrel per day hydrocracker that we think is an excellent candidate for conversion. We have a lot of work to do to understand the site balances and the logistics and the feedstocks before we would move ahead. But on the surface, it appears to be an attractive low capital conversion candidate. Probably, the key triggers would also be ensuring that the demand is there in the state of Washington because if we're going to be producing renewables in Montana, we're going to want to be moving it into and taking advantage of our market position in Washington.
The next question comes from Jason Gabelman with Cowen.
Congrats on the deal. I just wanted to first round out discussion on maybe the mid-cycle EBITDA that you provided. It would be helpful if you could provide per barrel OpEx, and then what you're considering in terms of our crude diff relative to WTI. I think that would be helpful.
Sure. So Jason, I think we're assuming, based on 50,000 barrels per day of throughput, again, the nameplate on the plant is 63,000 barrels a day. So we're assuming 80% utilization that you're going to be running at OpEx per barrel of approximately [ $10 ]. And so I think that's the starting point. And then I think we've given you some of the crude diffs to be thinking about. And again, we're going to be principally taking delivery of Canadian heavies off of Express pipeline and a couple of the other pipes that originate out of Canada. So should be relatively low-cost deliveries of heavy crude into the plant and then the other kind of 35% is going to be more light and medium grades out of Canada and then some domestically sourced barrels that come up from the Rockies into the plant. So happy to work with you a little bit more on the diffs, but I think that's -- we're trying to give you a good indication of the overall feedstock mix that -- with the plant can run.
Yes. Yes. And I appreciate you giving us a crude diet. Maybe if I ask the diff question in a different way, do you expect in that mid-cycle EBITDA -- just given WCS diffs are pretty wide right now, do you expect diffs to remain wider than, say, pipeline economics? Or are you kind of embedding pipeline economics in the WCS diffs?
I think we're embedding pipeline economics in there, and I think we're running for a mid-cycle probably, assuming WCS crude diffs is about a $14 differential discount to TI.
Okay. That's helpful. And then my other question is, I just wanted to go back on the maintenance comment that you made because. I believe there was a fire in the site earlier in the year, and Exxon has been in the market trying to sell it. So I'm just trying to understand, is there -- is your understanding that maybe there's some catch-up work that needs to get done and maybe maintenance is a little elevated in the near term? Or do you expect kind of maintenance spending to be more ratable in line with the guidance that you provided?
Jason, let me handle this first. Let me first just note that the impact of the March 2022 fire is, I think, behind us. The refinery is back up. It's running at normal operations. It's reliability has been high recently, and the incident has been fully investigated and root cause has certainly been identified and remediated. And I think this is one of those events that probably be shared broadly within the industry.
I'd also note, just in terms of maintenance, this is going to be one of the more challenging of our existing plants to operate. You think about the combination of cold weather conditions, a heavy [indiscernible] or crude diet, fluid coker operation. I mean all that creates a need for a lot of routine maintenance that will also reduce mechanical availability. And as Will noted, we targeted this assuming 50,000 barrels per day or an 80% utilization, we hope to do better. We plan to invest in the plant to try to make it better, and we expect to work closely with the team there to devise strategies that improve on these results. But to be very clear, our synergies today do not include any assumption that we increased throughput or reliability. This is just more upside.
Got it. Great. Congrats on the deal again.
Next question comes from Sunil Sibal with Seaport Global.
Congratulations on the transaction. So a couple of questions for me. I think you mentioned 40,000 barrels per day on Express pipeline. Could you indicate how long you have been or how long has been your nomination history on that pipeline?
I don't think we'll get into the specifics of the commercial terms on this call, Sunil. I think, suffice it to say, there's adequate modes of transportation to get grades of crude into the refinery. And again, I think we're comfortable with the position on Express and other lines in and out of the facility.
Okay. And then with regard to the other infrastructure assets that come with the acquisition, I think you mentioned $35 million of EBITDA. Are there contracts -- or what percentage of that EBITDA is from contracts from third parties? Could you indicate that?
So I think at the end of the day, the Yellowstone product pipelines are FERC common carrier line. And so again, the 40% ownership in that is probably you could look at that as third-party, although we will clearly be a significant shipper on that line with our production of the facility. And then largely, we'll be moving our own products via our own proprietary facilities in and out. So I think I would say, it's largely serving the existing distribution of products from the Billings refinery?
Okay. So the counterparties essentially builds refinery again, correct?
That's correct.
Okay. And then last one for me. What kind of throughput has the refinery seen over the last couple of years?
I think we just look at this as the -- we'll tie back to the 50,000 barrel per day on average number, and this is the way that we're modeling on a go-forward basis in our assumption.
[Operator Instructions] The next question comes from Paul Cheng with Scotiabank.
A quick question. On -- with the supply agreement with Exxon, how long is the duration? And then do you have an evergreen renewable agreement? Or that it will expire at some point? And also in that agreement, who's actually going to retain the RIN when you sell to the service station you or Exxon or [ SSB ]?
Yes. So Paul, I don't think we'll get into the term, but I think suffice it to say, long term. And we think the long term means more than 10 years. And so -- and then I think just with respect to the RINs, ultimately, we look at -- the majority of the fuel that we're going to sell is blended. And so our net RIN position will be a little bit shorter than we currently are, but I think we largely expect to retain the RIN and get full blend value for the fuel that we're selling.
And also, can you talk about the liability? So common package in the industry is under you watch, my watch, but Exxon has done a deal in the past where that all their liability has been transferred to the new one, even on the legacy liability. So can you discuss that? What's the arrangement here?
Yes, Paul, we're not going to get into too much detail on the liabilities, but yes, it's clearly kind of a clean break structure. As I look at it, really all of our refining operations at this point are heavily regulated, and they all have significant obligations to reduce the risk of environmental release. And sites like this also bear obligations associated with just the long term of operations. Exxon has a strong team to manage their obligations. They've done a great job of managing the risk on this site, and we're comfortable with the environmental obligations that are being borne by the site based on our view. And we don't think it's any different than the risk and obligations for environmental risk than any of our other sites.
This concludes our question-and-answer session. I would like to turn the conference back over to William Pate for any closing remarks.
Thank you, operator, and thank you, everybody, for joining us today. The Billings team and their assets are a perfect fit for our operations with multiple advantages for our combined enterprise, and we look forward to closing this transaction next year. Have a good day.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
