AXP Energy Limited (AXP) Earnings Call Transcript & Summary

Good morning, everyone, and welcome to today's webinar. My name is Alex Paull from Investor Stream, and I'll be your host today. Presenting to you this morning is AXP Energy Chief Executive Officer, Tim Hart; and Chief Operating Officer, Greg Grotke, who will be discussing the company's performance for the quarter ended 31 December 2022, and the key objectives for the upcoming quarter and throughout the calendar year 2023. There will be a short presentation on this progress, and Tim and Greg will be on hand to address any questions following the presentation. The presentation is currently being uploaded to the ASX and so you should be able to download it from that platform very shortly. A copy of the webinar will also be available on AXP's website and social media platforms today. But without further ado, I'd like to turn it over to Tim to kick things off for us. Tim, the floor is yours.

Thank you, Alex, and thank you all for tuning into the webinar today. In the presentation, we're going to be going over our Q2 results, and then we'll have an operational discussion about this blending issue that has been so impactful to the business as well as other things. And further, we'll discuss a few details about our fields as well as some of our near-term plans. I am pleased to be presenting with Greg Grotke today. And as many of you are aware, Greg is our Interim Chief Operating Officer and has been intimately involved with the business for the last several months as we work towards solving some very difficult legacy issues and develop our plans forward. And although you've had some introduction to Greg, with his Investor Stream interview several months back, for those who missed it, Greg comes to us with a significant background in oil and gas, with 30 years of experience in various technical and leadership roles at companies like BP Amoco and Noble Energy, and he's a welcome addition to the team, and I feel privileged to be presenting with him today. With that said, can we advance to Slide 3, please, Alex. So this shows our net revenue broken down by hydrocarbon. And although our quarterly net customer receipts were up 17% and we had a positive operating cash flow, there's a very noticeable 42% decline in net revenue. And so let's explore why that is. Well, 56% of this decline was related to a reduction in NGL sales. And this is directly due to the fact that we're not buying blend materials, which is a very good thing. And blending is a bit of a complicated matter. So we have a couple of slides dedicated to it later on in the presentation. The second largest contributor to the net revenue reduction is that there was a 37% drop in realized pricing. Commodities are softening and gas has taken a significant downturn. That said, we hung in there with approximately $1.94 million at quarter end. Next slide, please, Alex. So we had a 6% decrease in gross production and a significant portion of that was reduced NGLs due to higher-than-usual direct sales. Oil and gas were slightly down due to the impacts of inclement weather which is typical for this time of the year. We did see a 6% uptick in net gas sales by volume due to performance improvements with our midstream provider, which I was really happy to see. And we held steady at just under 18,000 barrels of oil inventory. And as promised, we have a few detailed slides on blending that Greg will be presenting next. With that, over to you, Greg.

Thank you, Tim, and thank you for the introduction, again, and really appreciate all those that have joined us today. This topic and this next topic about the NGL blending is quite complex. And so as we get into the next slide here, I'll start sharing some of those details in the overall blending challenges that we faced. And then I'm sure that we'll hit some more details during the Q&A as well. So just to remind folks that have been in some of the prior webinars, you know that we've been dealing with blending for quite a while. And it is not a new issue for the company, yet it is something that really increased dramatically in late 2021 and throughout 2022. And the reason for that is because there is -- there are existing regulations in place related to the vapor pressure and the amount of pressure that can be in vessels, railcars or tanker trucks when they're on rail and road. And the most efficient, the best way to get hydrocarbons, oil, gas and NGLs to market our pipelines. And with potentially no pipelines in the area or limited pipeline capacity, we look to rail, and the least efficient is typically trucking. So as we got into this last year with increased blending requirements, the only direction we had to go with our NGLs was rail to Texas. And so given that we were shipping our NGLs to a part of the country that is much warmer during most of the year, we had to deal with purchasing blending material and bring it up from Texas to Tennessee to blend with our produced materials and then ship that blended material back down to Texas for sale. And that was the only market that we had all the way up until the first quarter of our fiscal year 2023. And you can see in the graph below that is when we hit our peak problems and challenges with blending. So fortunately, we were working on other ways to get our NGLs to market, and we have at least one additional channel to market, and that is via truck to a facility in West Virginia. So now that we have at least 2 markets, rail to Texas from Tennessee and trucks to West Virginia, that gives us a little bit more flexibility going forward in managing this. And we did get to the point at the end of Q4 of 2023 or in December, having a full month where we didn't have to blend any product as all of our product move via truck to West Virginia. So if you could go to the next slide, please, Alex. Now when we start diving into the details of how this has impacted us financially, we look back and we see that when we sold a little over $3 million of blended material, it actually costs us over $7 million to receive that material. And the reason is because it was coming from a long distance, the material and the blend product from Texas had to be transported via rail, which is one of the most efficient ways to get product to market. However, we had to pay for blending fees and the time to receive that product and ship -- blend that product and move it back to Texas, had carrying costs that negatively impacted us. But as I mentioned in the previous slide, we are fortunate to be able to find other access to market and other ways to ship our NGLs north and not have to deal with the warmer weather and the more volatile liquids increasing that vapor pressure when that product is shipped to Texas. So as you can see on this slide, as we work through the issues and challenges in the bar graph below, you can see that we struggled to cover our costs, and we're continually losing money in this blending process while getting our gas to sales through that gas processing plant. So going forward, yes, we're fortunate that, as I mentioned, in December, we had no blending requirements at all. And as we go forward, we'll continue to see better markets and better channels to sales up north. So we won't have to deal with the hotter summer months in Texas. And one of these -- the current market that we have going north to West Virginia does allow us to borrow the blending material. And when we ship that blending material down to Tennessee, blend it in the truck and ship it back, that has -- doesn't have nearly the negative impact that we've seen in this process that we've been working to fix and have found solutions. So as we get into the summer months, this year, we will continue to look for additional options and opportunities to reduce this cost that was such a burden for us this past year. So with those slides on blending, we'll move on to production rationalization and have Tim go ahead and talk a little bit more about where we're headed.

Thanks, Greg. So my intent behind this slide is to talk through our Appalachian Basin assets. And the Henry Hub natural gas spot price today is $2.65 an MCF. It's beyond question that this is going to have some impact on our business. And with our company primarily focused on gas production in the Appalachian Basin, this decline in natural gas price necessitates that we change what we're doing. And thankfully, we have a fairly diverse portfolio of assets that includes multiple hydrocarbon streams as well as 16 different sales channels for the oil, gas and NGLs that are produced. So 72% of our wells in the Appalachian Basin are dedicated to a single very high-cost sales channel, as outlined by the red dotted line in the image. And at current prices, gas sales through the sales channel is not profitable. There are 7 different direct sales customers and 62 oil wells within this area that are profitable, and we'll continue to operate and enhance the wells that service these sales channels. At the same time, we'll continue to work with our midstream partner to improve our margins within the AMI, but we cannot operate these at a loss. And the reality is that we've inherited a very difficult sales channel here and we've been working to try and improve it and we'll continue to do so. However, we do have 8 fields outside of this area that sell into other sales channels at a much higher profit margin. There's about 320 wells in these 8 fields that account for approximately 24% of our total gas production and these fields are shaded in green on the map. The upside is that these fields have had very little work and have a tremendous amount of upside. So at current gas prices, our focus will shift to oil and gas production in these fields. And to date, we've only been focused on our KJ field, and Greg will provide some additional commentary on this field in the next slide. Back to you, Greg.

Thank you, Tim. So in that slide that Tim was just reviewing. You'll recall that KJ is off to the west of the area that we were just talking about. And in the KJ field and as we zoom into the KJ field, we have 236 wells currently in the KJ field. And we're working on all of these wells to increase production. The current production is a little over 1 million a day. And when AXP Energy first acquired these assets, that production was around 200 a day. So we've had a fivefold increase in this field over the last couple of years. We have some good -- some favorable pricing, and we have 32 wells that have been tied to new pipelines and have enhanced production. And you can see the pipelines that have been replaced enhanced in blue on this slide. And what that does is allows line looping and the ability for gas to flow in a couple of different directions and in a couple of different ways through the field. It also enables us to prepare for recompletions that you've heard us talk about in the past. We had a couple of recompletions last fiscal year out in Haley's Mill in the Illinois Basin. And we identified 5 recompletions this year and have already completed 3 of those 5. Some of these may be familiar to you. We've had a number of questions recently about the Terry Carol #3. That was our first recompletion. And then we have 2 other recompletions, [ HE61 and HE68 ] up in the upper left portion of this slide. And we are flowing back these wells. And 1 of the things that we have learned, Alex, can you go back to the previous slide, please? As we go back to the previous slide, if you look to the west side of this slide, you'll see a number of blue lines around that KJ field in the west side of this slide. And that is another offset operator that has done a tremendous amount of work similar to the recompletion work that we're doing. So thank you, Alex. You can go forward 1 slide now. So as we get into this work, 1 of the things that we've done since I joined the company about 3 months ago. And I can't believe that it's just been a little under 90 days, and we were talking all about the recompletion opportunities and the pay behind pipe. One of the things that we've done is really looked at that offset operator and what they've done and how they've been successful in what they've seen as highly variable results in the recompletions yet we do have the ability with the log control that we have and the offset work from the offset operator to know that there is -- there are hydrocarbons behind pipe, both gas and oil. So these are the opportunities that we've been focusing on these last few months, however, given the current price environment, 1 of the things that we've decided to do is to hold off and not pursue those next 2 recompletions in the next few months. And we'll wait until we have a more favorable commodity pricing to move on the next 2 opportunities. Now with that said, we have over 100 wells that we can work on like this, yet in the current pricing environment, we're going to continue to analyze and understand what we can learn from the offset operators, the existing logs that we have in these wells and be prepared when we have a better pricing environment to go after these recompletions. So with that, on the next slide, I'll let Tim go ahead and share some of those near-term focus and adjustments to where we're heading here in the near term. So you can go to the next slide, Alex.

So with the current environment with gas prices, we're going to be doing some restructuring and cost reduction efforts. And those things are all underway right now. We are identifying and assembling all of our lowest net revenue interest wells, and those wells are on deck to be shut in. We're considering divesting of some noncore leases, leases that we've had difficulty and challenges with getting the margins that we've wanted to throughout the time that we've owned them. And as we suggested, we'll be shutting in wells with high-cost transport and processing. We really don't have a choice. It certainly isn't our -- we're not happy about this, but we've got to make sure that we're healthy going forward in this new price environment. And 1 of the things associated with that is lower TGC costs. And so our transportation and gathering costs will be reduced substantially as we're able to reduce production inside of these high-cost fields. The other thing that you always have to be mindful of when you come into an environment like this with the low gas prices are, there's a lot of people that just don't have the stomach anymore for low gas prices. And so we've got to be looking out for those opportunistic acquisitions that are possible and potentially some JVs and maybe divesting of some of our other assets can help us take advantage and leverage some of these items that might come on to the market as a result. So we're continuing to focus on margin improvement and growth for the new pricing environment. As Greg mentioned, we've reduced our reliance on blend material in the winter as it's colder. We don't have to blend because the temperature inside the transport vehicle doesn't increase as much. And we are working towards coming up with a similar solution in the summer. We think that we have this mostly solved, but we've got some more testing to do once the weather becomes warm. We're going to grow and stabilize the oil production. We've got to work on our logistics. There's a bunch of wells that need work, a lot of low-hanging fruit that we can attend to. And also growing our gas production outside of our largest sales channel until we can secure better terms and/or we get better pricing. Next slide, please, Alex. Greg, did you have anything you wanted to add on that last slide?

No, that's good, Tim. And I believe we'll probably get some more questions about where we're heading. So yes, I think we're looking good as we get towards the end of the slide deck here.

Yes. So this slide, for those of you who have stuck with us for a bit will not be a new slide. And we're discussing it today because the strategy of our value creation has not changed. Our required enhance and produce as well in effect. And the good part about it is I feel like we're operating in an area that's conducive to this. It's in the Southern Appalachian Basin, it's highly segmented and there's lots of opportunities for us to consider expansion through picking up assets that are in distress as we move through these challenging times. So with that said, that concludes the presentation, and I'll turn it back over to you, Alex, to move through the questions.

Thanks, Tim. Thanks, Greg. Look, we will get started on the questions now. And I'd just like to start if we can with the Elite Mining operation in Colorado. So Tim, following the current modifications and upgrades, a couple of questions here. Firstly, what -- at what approximate date will the Elite Mining project be fully operational from a gas supply point of view? And then approximately on what date will AXP be able to exploit these associated oil reserves for sale to third parties?

Alex, the -- I'm going to give a more general answer for this. The Elite Mining operation in Colorado will be fully functional or is scheduled to be fully functional this quarter. We have made some very good progress there, and we were actually running the site for an extended period of time, but had some difficulties with the third party that was responsible for supplying the power generation. We're the gas supplier, there's a third party that's supplying power generation, and then Elite Mining is supplying the EMUs and the computers to do the cryptocurrency mining. So we've been through a couple of iterations with this. And we've got a new third party that is bringing generators in. The team was actually on site, Elite Mining, this new third party and our group all day today. And the new generators are supposed to be moved in this coming week. So once those generators are moved in, we will connect them up to the system and fire them up. And if they are reliable, then we have a fully functional mining operation in Colorado. So...

So just on -- once both the gas and oil reserves are able to be exploited, what are the projected effects on AXP sales and profits?

So a couple of things here, Alex. One is we're starting with a small mining operation. We anticipate this initial operation to be 400 MCF per day at full production. But one of the things that I want to point out is that this -- the Colorado assets are just a small part of our asset portfolio. And so our primary focus, although I'm very excited about getting this mining operation up and running, our primary focus still remains in the east, in the Illinois Basin and the Appalachian Basin.

Thanks, Tim. Now I'd like to turn this over to Greg, if I can. So we've had a number of questions come through about pricing, especially oil price, in particular. Firstly, Greg, could you just clarify the pricing that we're talking about here, what's that based on? Is it Brent or U.S. NYMEX or WTI?

So we do look at the U.S. NYMEX and WTI and do not tend to look at the Brent pricing. And so that's focused on the U.S. pricing index because all of our producing assets are in the U.S.

Thanks, Greg. So what was the average gross price achieved in the quarter? And what expenses are deducted from the gross price we get to arrive at AXP's net price of USD 33.48 barrels of oil equivalent?

Okay. So I do not have the gross price this past quarter in front of me right now. But one thing that is -- that needs to be clarified or one thing that is probably worth pointing out is that the net price is calculated based on our net production sales and our total revenue. And so with asking about what drives a net price of $32.48 per BOE, I think, was the number that you shared there, Alex?

That's correct.

Yes. So that sounds like a very low price for a barrel of oil equivalent. But keep in mind that 60% of our production is natural gas. So just this week alone in the United States, the BOE pricing for natural gas is about $15 a barrel or $2.5 an MCF. So that is a part of what drives our price. Now we have another about 20% in NGLs and 20% in actual oil production. So that's what drives our focus now and what Tim finished up in the end of the presentation on looking at where can we increase our oil production, say, in the Illinois Basin and even to some extent in Colorado, where we can get more liquids production, which would then drive up more revenue and an increased price for BOE.

So the world oil price yesterday was reported as Brent was USD 82.84 and you've acknowledged that you don't quite focus on that one as much. The U.S. NYMEX was USD 76.41, but AXP only achieved an average price of USD 32.48 BOE. Where is the difference go?

I think I was able to address that quite a bit in the previous answer. And just another thing to reiterate, on top of that is a blend. The BOE is 60% natural gas, roughly 20% NGLs, 20% oil. It also is a net price. So when you look at what we produce at the wellhead and the fuel that goes into the compressors to get the gas to -- the gas plant, 20% goes to NGLs, roughly and then 80% of that gas stream goes to gas sales. And so we also have to pay our royalties on -- to go from gross to net as well. So the landowners, and that is something that is unique here in the United States. I do believe we have a number of people on the call in Australia and elsewhere around the world and be very similar to the taxes and royalties that are paid to the governments that own the mineral rights and in other countries, but we have numerous landowners that we pay off of the top of our revenue. So the combination of royalties fuel, shrink and loss in the system and the product mix is what drives that lower price per BOE.

Sorry, Greg, just to sort of finalize the discussion around pricing. Broadly speaking, what's your view on the outlook for hydrocarbon prices, both short term and maybe for the second half of the calendar year?

Alex, we certainly hope we see some recovery, certainly on the natural gas price that we've currently seen. We know that here in the United States, we've had some challenges in exporting and offtake of natural gas along with the past quarter or 2, I'm sure we are not the only company that was looking at some very high gas prices up around the $8, $9 an MCF range. And thinking about what additional projects we could do to take advantage of those higher gas prices and now we are in a much lower price environment. So while we look forward to a little bit better gas pricing going forward, oil has hung in there. And the pricing, you look at the last, say, 6 months, we've seen more than a 70% drop in gas price, less than 10% drop in oil price. So if we could maintain or we may actually see oil drop off a little bit, but we're working our business and managing our portfolio of assets no matter what the pricing environment is. And that is something that we will continue to do and continue to communicate to our shareholders as we go forward.

Thanks, Greg. We had a number of questions coming through regarding production as well. So we might move on to that now. So as it's currently constituted AXP had kept approximately even levels of production across the last 5 quarters. We're talking roughly 200,000 BOE per quarter. Has not raising production being a strategic move due to improper margins and relationships with other offtakers. And I guess further to that, do you see that increasing production by 50% to roughly 30,000 BOE per quarter is something that needs to be done or can be done?

Certainly, Alex, I'd say that we could -- take a look at the pay behind pipe and the opportunities to accelerate our recompletions to shoot for a 50% increase in production. However, in the current commodity environment -- commodity pricing environment, that would not be wise and that is not something that we look forward to doing here in the near term. As far as the 5 quarters previously and flat production, we are very fortunate to have an operations team that has been able to maintain production and identify projects to incrementally add new production and replace reserves while we've maintained this production, there's another operator in the area leading operator that touts an 8.5% decline on their base production. And in our base production, we do see 4%, 5%, 6% decline in our base production, yet we have to work hard to maintain that flat production that we have maintained over the past 5 quarters. There are other operators that may see base production decline rates, 20, 30-plus percent. And those tend to be the larger operators for the north of the Appalachian Basin and a lot of operators that have much greater capital investment programs in place and are out drilling shale wells, bringing on a lot of new wells and it makes it more difficult to maintain production and to grow production as this person is asking what would it take to get that 50% increase in production. With higher commodity prices, we may consider or look towards when it would make sense to increase our pace of capital investments and bringing on new production yet at this point in time, looking to maintain production and replace reserves has been a place that we have been in the past few quarters and will likely be in the next few quarters ahead.

So Greg, regarding oil production. The announcement stated that oil revenue fell 39%, predominantly driven by a fall in realized commodity prices. However, the announcement also states that the net oil sales fell by 1 quarter and realized oil price also fell by 18%. Is there a reason why management is attributing the decline in oil revenue primarily to stop the pricing instead of sales volume decreases?

Alex, I believe in the announcement and here in the presentation, we've talked about it being a little bit of both. It is a combination of the pricing along with the sales. And 1 of the things that Tim has pointed out in the past and something that for those that are potentially halfway around the world and enjoying the summer months, we are coming off of what was a very brutal winter and holiday season, and hopefully, we're recovering from that yet even with the oil that was produced, we did have some challenges getting that oil to market with the brutally and cold conditions that we had over the holidays and also with the work that we had to do after the floods late last summer to repair the road. So we do look forward to, hopefully, an early spring and an opportunity to move more oil to sales in the near future. And so to answer this question, though, it was a combination of both the pricing and the sales volume decreases.