USA Compression Partners, LP Q1 FY2020 Earnings Call

Good day, everyone, and thank you for standing by. Welcome to the USA Compression Partners LP's First Quarter 2020 Earnings Conference Call. This conference is being recorded today, May 5, 2020. I would now like to turn the call over to Chris Porter, Vice President, General Counsel and Secretary.

Good morning, everyone, and thank you for joining us. This morning, we released our financial results for the quarter ended March 31, 2020. You can find our earnings release as well as a recording of this call in the Investor Relations section of our website at usacompression.com. The recording will be available through May 15, 2020. During this call, our management will discuss certain non-GAAP measures. You will find definitions and reconciliations of these non-GAAP measures to the most comparable GAAP measures in the earnings release. As a reminder, our conference call will include forward-looking statements. These statements include projections and expectations of our performance and represent our current beliefs. Actual results may differ materially. Please review the statements of risk included in this morning's release and in our SEC filings. Please note that information provided on this call speaks only to management's views as of today, May 5, and may no longer be accurate at the time of a replay. I'll now turn the call over to Eric Long, President and CEO of USA Compression.

Thank you, Chris. Good morning, everyone, and thanks for joining our call today. Also with me is Matt Liuzzi, our CFO; and Bill Manias, our COO. This morning, we released our financial and operational results for the first quarter of 2020, achieving a solid quarter of operational and financial results. I plan to briefly highlight the quarterly results and then spend more time discussing our business model, what we are seeing out in the field, how we are managing the business in this uncertainty, and ultimately, how we expect the rest of the year to play out. The first quarter went very much as we had expected. Revenues were $179 million, up approximately 5% over the first quarter of 2019. And likewise, adjusted EBITDA of $106 million was up about 5% over the year-ago period. We achieved a gross operating margin of 66.9% and an adjusted EBITDA margin of 59.3%, both metrics consistent with year-ago periods. Average utilization throughout the quarter was 92.5%, down slightly from the year-ago period, reflecting a modest amount of returns, particularly as we move towards the end of the quarter. We ended the quarter with approximately 3.3 million active horsepower, consistent with the year-ago period at about 3.7 million total horsepower in the fleet. Average pricing across the fleet increased modestly during the first quarter, reflecting some new unit deliveries as well as the impact of selective service rate increases previously negotiated. We saw average monthly revenue increase to $16.89 per horsepower, up from $16.82 in the fourth quarter. This reflects our previously discussed expectation that pricing gains would moderate as we move into and through 2020. Our capital spending during the quarter consisted of $46.5 million of expansion CapEx, which included the delivery of 27,500 new horsepower, primarily consisting of large horsepower units. You will note that in our earnings release, I mentioned reducing our expected growth CapEx spend for 2020 by about 25%. That will take place over the back half of the year. Some of that growth CapEx spending had already been locked in by the time we had the events of early March and everything that has followed. We anticipate cutting any discretionary spending that we have not already committed to. However, we will continue our normal maintenance activities in order to keep our assets running in a safe and efficient manner. At this point in time, we expect expansion capital spending to total between $80 million and $90 million compared to previous guidance of $110 million to $120 million. While our total new unit delivery estimate for the year is 62,500 horsepower, we will be pushing the timing of some deliveries back towards the second half of the year. The capital savings we anticipate are due to cutting out planned reconfigurations and make-ready work. As I mentioned at the outset, the first quarter went largely according to plan. Based on the results, the Board decided to keep the distribution consistent at $0.525 per unit, which resulted in a distributable cash flow coverage ratio of 1.08x. Our bank covenant leverage ratio was 4.56x for the quarter. Just as a reminder, the quarterly distribution is a decision that our Board of Directors makes on a quarterly basis. As has always been the case since our IPO, the Board can opt to maintain, reduce, or suspend the distribution as it deems most appropriate on a quarterly basis. We are proud of the efforts of the dedicated men and women of USA Compression. They delivered a solid first quarter, and even as the pandemic began to play out in March, continued to work safely every day for the benefit of our customers and the success of the partnership. As everyone listening to this call is aware, our equipment allows natural gas to move into and through natural gas pipelines. While the coronavirus and the oil market disarray have occupied many headlines, our equipment is still critical to moving existing and future gas production, and our employees are still required to keep it in good running shape. So again, a big thank you to all of our hardworking employees. A little bit on the macro market on natural gas and crude oil. Matt and I have taken many calls over the last few months, and one recurring theme has been the very different market dynamics currently affecting crude oil and natural gas markets. Sometimes it gets lost in the fog, but when you look at the entire energy sector together, folks forget that USA Compression remains a business primarily driven by domestic natural gas demand. That has not changed, even in the face of $10 crude oil. We continue to take a long-term view on the overall need for and production of natural gas. Certainly, some aspects of the gas market are impacted by the crude oil market; however, that has happened for years, and the gas market has always adjusted, which we will discuss shortly. While we are actively managing through the current weakness in the energy market, our long-term view has not changed. We continue to believe that natural gas will play a more and more important role as a clean fuel of choice, perhaps even more so as the fragility and geopolitical implications of the oil markets are made apparent. Talking about the energy markets, to put it succinctly, oil has been absolutely decimated. At first, there was concern over global demand impacts due to the growing corona pandemic with demand softening due to the uncertainty of the global economy. The Saudis and Russians failed to come to a production agreement in early March, combined with the acknowledgment of the economic impact of the pandemic. Oil demand is down significantly and expected to remain so until recovery actions are fully underway globally. Some estimate global oil demand destruction to be as much as 10, 15, even 30 million barrels a day, and it's on a global market of approximately 100 million barrels per day. So a fairly significant impact. The exact duration and depth are obviously unknown at the present point in time, but many observers anticipate a tough go of things for a while. In response, you've seen decisive actions by those most affected by collapsing oil prices: significant CapEx reductions by exploration and production companies resulting in vastly reduced rig counts, the beginnings of oil well shut-ins in various basins, and crude oil storage reaching maximum levels. Refinery runs are also down significantly. The CapEx reductions around new drilling will slow the rate of overall production growth or even result in decline in a given basin or for a specific customer. Though shale type curves, while steep at first, tend to flatten out significantly after a few years when a given well moves into more of a steady-state existence. In short, if the CapEx cuts hold, producers will not be drilling enough new wells to offset the decline of their existing flush production wells. Over time, a large number of wells will be in the flat steady state part of the curve where decline has also meaningfully slowed. Recall that this played out in the Fayetteville and Eagle Ford shales about five years ago after rapid production growth. We have seen this occur in Appalachia over the past several years as well. A significant component of USA's larger horsepower fleet is deployed in infrastructure applications, exhibiting the flat steady-state shallow decline profile. So even without new drilling activity, compression is continually needed to continue to move these stable volumes of natural gas. This is an important concept that often gets overlooked. Another extremely important concept that I have discussed in literally every investor presentation since our IPO relates to compression horsepower and declining reservoir pressure. Diving into the physics of gas compression for just a minute or two, as pressures decline, moving the same volume of gas requires an exponential increase in compression horsepower. This is a hugely important and a technical concept rarely appreciated and understood by those outside the industry. I'll say it another way: assuming constant pressure, to increase gas volumes requires more horsepower. Conversely, to maintain flat gas volumes in a declining pressure environment also requires more horsepower. But what happens when gas volumes decline and pressures also decline? It depends. Compression horsepower may decline a little, remain stable, or might actually increase. The characteristics of individual wells, specifics of the reservoir rock and fluids composition, all factor into this multivariable quadratic equation. Simply stated, for both associated gas and dry gas applications, even though gas volumes may be on the decline, required compression may actually increase as pressures also decline. To put things further into perspective, for depletion-driven oil production, as reservoir pressures decline over time, gas-oil ratios typically increase, leading to more associated gas production per barrel of oil produced. These important concepts are fundamental to the reason that during periods of reduced drilling activity and even declines in produced volumes, we have not historically and do not expect to experience dramatic declines in the need for our large horsepower compression services or required horsepower. The dynamics I've mentioned above, along with the relatively resilient demand, have historically made large horsepower compression a less volatile business. Of course, there is still a great deal of uncertainty about how everything settles out in the commodity markets, but we feel good about the gas market and its long-term prospects. The natural gas markets have actually been more positive, and for good reason. The demand for gas, while having some seasonality, remains resilient. There will be some near-term impact to domestic gas demand as schools and businesses have temporarily closed their doors due to the coronavirus. For most areas of the country, this has occurred during seasonally mild weather, and the impact on demand has not been as significant. You also need to remember where most of that gas demand ends up: power generation, both commercial and residential, as well as industrial purposes like chemical plants and other industrial manufacturing. Estimates vary, but generally speaking, observers are discussing demand destruction on the gas side in the single-digit Bcf per day range. On a market of 95 to 100 Bcf per day, that is more akin to a minor speed bump, which speaks to the relative stability in the natural gas market, underlined by that resilient baseload demand. There's also an interesting dynamic that we believe will play out in the gas market over the next 12 to 24 months. Right now, we are seeing some moderate demand disruption in the face of continued supply. Even with announced E&P growth cap cuts on the oil side and the expected decrease in associated gas supply from recently drilled oil wells and steep decline flush production mode, it will take a few months for that to show up in the data. Over the next few months, we expect to see a supply overhang on gas, which will add to storage levels, keeping a cap on the near-term price. At some point in the early fall, underground gas storage could reach fairly full levels, but that is expected to happen just as declines in production really start to kick in, that gas and storage will be available to serve that relatively stable baseload demand during winter heating months. While the ultimate impact of associated gas production currently is uncertain, we believe the natural gas futures market gives us an early indication. Recently, January 2021 gas futures were over $3 per Mcf, and no month throughout the entire year was below $2.50 per Mcf. As always, when supply and demand get out of balance, prices react and serve to balance the market. Ultimately, assuming we do see significant reductions in associated gas production, that required supply will need to come from somewhere. You're hearing more of these days about new activity in the Marcellus, Utica, and Haynesville shale plays. We see continued activity in the all-important Northeast. The price of gas will ultimately ensure there is enough gas to supply the demands of the marketplace. Obviously, the drivers behind the crude oil and natural gas markets are not the same, nor do we think that the recovery timeline and near-term outlook will be the same for both commodities. While it is hard to predict exactly when and to what extent things will normalize, the relatively positive outlook for both natural gas pricing and resumption of stable demand should bode well for our business. So let's turn to our specific USA business model. The USA Compression's business model has remained very consistent over the past 22 years, whether as a private entity or the last seven years as a public partnership. We have always focused on large horsepower compression used in large regional infrastructure-oriented facilities. These facilities move very large amounts of natural gas. These are not facilities that are easily shut down, and the cost of demobilization, which are borne by our customers to send home a USA Compression asset, may be extremely expensive. These barriers to exit, as we call them, provide further support in times like these to mitigate the return of iron that our customers most likely will need after a few quarters of excess oil overhang works its way through. We have always pointed to the stability of this business model and continue to be optimistic about the future of large horsepower compression. Over the past couple of years since closing the CDM acquisition, we've made an effort to secure additional contract tenure after the primary term has passed, which has moved a number of our contracts to a month-to-month duration. Historically, we had anywhere between 40% and 50% of our assets on a month-to-month basis. Coming into this downturn, we are positioned better than we have ever been, with our recontracting activities reducing our month-to-month exposure to approximately 35%. We also review the loading profile of the month-to-month assets, ensuring that those that are loaded are needed, which further reduces the likelihood that a unit gets put on hold. Even with about 25% of our horsepower deployed in the Permian and Delaware basins, primarily serving associated gas production, we have the vast majority of our assets serving either dry gas activities or natural gas handling activities such as those connected to gas processing plants and large-volume centralized gas lift applications beyond the flush production stage and in the stable, shallow decline steady-state mode. So what are our customers up to? We last saw a commodity downturn back in the 2014-2016 timeframe, with crude oil down as low as $27 per barrel. We experienced fleet utilization decline to the mid-80% area, with the larger midstream horsepower exhibiting greater stability as expected. The smaller horsepower well mid-oriented gas fleet was where our soft spots surfaced. We took aggressive cost control measures and maintained relatively flat EBITDA and cash flow margins, all while cutting growth CapEx by almost 90% over two years. While this latest series of market events is somewhat different from the 2014 cycle, we have seen a similar response from customers. The initial shock of the crudely price decline prompted the return of underutilized assets at the customer's expense. This was applicable only for that portion of the fleet and their month-to-month contracts. These are predominantly smaller gas lift units that have low demobilization costs and are sitting on oil wells that have now turned uneconomical. We have seen some redundant larger horsepower units get returned as well. In some cases, the customer may have recently bought some units and decided to replace our equipment with their own. Overall, our customers are working to figure out what their future holds for their particular operations as well as for the overall industry, creating different motivations for different customers and different basins. In a few cases, customers have requested temporary and short-term rate concessions or the ability to move units to a standby rate while things settle down a bit. Depending on the customer, the contract, and proposed economics, we are considering these requests. We have seen the first wave of returns occur, and we will wait and see how much additional horsepower comes back. At this junction, the 2020 collapse has behaved much like the 2014-2016 decline, with an initial wave of returns followed by a much slower and somewhat nominal decline. We will continue to monitor returns closely over the next few quarters, where the risk of utilization declines from associated gas activities remains greatest. We have numerous levers we can pull depending on the depth and duration of this downturn. There still seems to be a sense among some observers that USA Compression is an oilfield service business with significant exposure to well plan activity and commodity price risk. This has been a common misperception over the years. Our focus has purposely been away from activities that introduce commodity price risk and is oriented toward larger installations serving demand-driven natural gas infrastructure applications. We have deployed significant amounts of horsepower in large multi-unit, centralized compressor stations over recent years. These installations have, in many cases, moved beyond the initial flush production phase and have settled into the steady-state phase with shallow decline rates, thus enabling relatively more stable volumes and pressures. As these wells age and reservoir pressures naturally continue to decline, more horsepower may be required to accomplish customers' operational needs. I'll now turn the call over to Matt to walk through some of the financial highlights of the quarter. Matt?

Thanks, Eric, and good morning, everyone. Today, USA Compression reported a solid first quarter to start off the year, including quarterly revenue of $179 million, adjusted EBITDA of $106 million, and DCF to limited partners of $55 million. In April, we announced a cash distribution to our unitholders of $0.525 per LP common unit consistent with the previous quarter, which resulted in coverage of 1.08x. Our total fleet horsepower as of the end of Q1 was largely consistent with where we ended 2019, right about 3.7 million horsepower. Our revenue-generating horsepower at period end increased slightly to a little bit over 3.3 million horsepower. Our average horsepower utilization for the first quarter was 92.5%. Pricing, as measured by average revenue per revenue-generating horsepower per month, was $16.89 for Q1, which again was a slight increase from the previous quarter's level. Of the total revenue for the first quarter of $179 million, approximately $176 million reflected our core contract operations revenues, while parts and service revenue was $3 million. Gross operating margin as a percentage of revenue was 67% in Q1. Net loss for the quarter was $602 million, inclusive of a $619 million noncash goodwill impairment charge, which I'll cover in a minute. Operating loss was $570 million in the quarter, also inclusive of the $619 million noncash goodwill impairment charge. Net cash provided by operating activities was $50 million in the quarter. Maintenance capital totaled $8.8 million in the quarter, and cash interest expense net was $31 million. To add a little more color on the goodwill impairment charge, based on our unit price at the end of the period, we performed an evaluation of the fair value of the business and the carrying value. The impairment charge reduces the amount of goodwill on our balance sheet to 0. I'd note that the goodwill was created more than two years ago; about $250 million was already on CDM's books at the time of the transaction, and the balance, about $366 million, was created as a result of the reverse merger accounting method used to account for the CDM transaction, whereby we were required to revalue the USAC balance sheet as CDM was considered the acquirer for accounting purposes. Given the recent events affecting the energy markets in general and the ongoing uncertainty, we are providing revised full-year guidance for 2020. We currently expect 2020 adjusted EBITDA of between $395 million and $415 million, and DCF of between $195 million and $215 million. At the midpoints of these ranges, these estimates reflect decreases of approximately 5% and 7%, respectively, from our previously communicated guidance ranges. There are obviously a lot of unknowns in the marketplace right now, and as things progress, we will continue to assess guidance throughout the year. Last, we expect to file our Form 10-Q with the SEC as early as this afternoon. With that, we'll open the call to questions.

And we'll start with TJ Schultz from RBC Capital Markets.

I think, first, so the comparison to the downturn in 2014 through 2016, I think was characterized into the mid-80s on utilization. So has this initial rush from some customers to return assets kind of taken you to that level right now? And just trying to think about a few of the differences between now and then and your fleet, meaning, on one hand, do you have maybe a higher mix of larger horsepower units now? And if you're 25% Permian now, what was your mix to associated gas in 2014?

Yes, TJ, it's Eric. So maybe a couple of things. When you look back to 2014, it was characterized as putting a lobster in a pot and bringing the heat up slowly. The lobster wakes up a year later, bright red and boiled to death. This drop happened very, very quickly. In 45 days, we had the initial round. The first wave of equipment returns we saw was predominantly the gas lift equipment, mostly from the Mid-Continent, and to a lesser degree, some coming out of the Permian. I think in our commentary, we mentioned owner-operators that returned some equipment to us. One customer, in particular, had purchased a bunch of equipment, anticipating using it as baseload equipment, while using USA Compression to variabilize the compression to meet their ongoing growth demand. Also Mid-Continent based, they saw their end users drop out, their customers drop out. Since they have taken delivery of north of 10 or 15 machines, and our units were on short-term contracts, when they went off the contract term, they sent those 10 or 15 machines back. So I think the way we categorize this first wave feels a lot like what we saw in the early phases of 2014 and 2015. What remains to be seen is what happens around the third quarter of this year. We're now in the June, July, August range, where the major production cuts are occurring. We've seen a lot of research reports suggesting that you will see continued shut-ins and curtailments between now and the end of the year. But I think what we’re hearing from our customers is that our equipment on these big facilities will still be needed; we are not turning things off completely, but we may be curtailing or throttling back. If you keep in mind, we've got six, eight, ten machines on a big central facility, so that stuff is not all getting turned off. They might ratchet things back to 80%, 70%, or even 60% of load, and you might take one or two or three and put them on standby for some time. But we're not receiving requests from our large central facilities customers saying, 'Come take your equipment home.' We're going to incur $1 million or $2 million of demobilization costs on the customer's end to send it home because what we're hearing from them is, while everyone is assessing what's going on, there's a common sense that after a couple of quarters, things will kind of re-equilibrate, working through the system, and our assets will be needed beyond that period.

And TJ, it's Matt. The only other thing I'd add is it's interesting when you look at the gas prices; Eric talked earlier about futures a little. You go back to 2014; in the middle of that year, gas was over $4. Over that 2014 to 2016 period, it decreased to under $2 by the time that downturn was over. The interesting dynamic we have now is sort of the opposite outlook; when looking forward, we see increases in gas pricing over the next 12 to 18 months, which I think is positive.

Okay. All makes sense. And then on pricing, it sounds like you're waiting on some decisions regarding rate concessions for certain customers and you may be balancing that against taking back some assets and moving to different basins. But could you expand on what you are looking for in deciding on some of those rate concessions? And if you would provide standby rates, what are those typically relative to working or contracted rates?

TJ, a fair way to say it is that, to the extent we do anything, it will be temporary in nature, very short-term. We have not had a wholesale request across the board from all of our customers or even a large number of customers. I would say it tends to be more basin-specific and asset-specific. Based on our large horsepower, large gas-handling central facilities, we have not seen many people asking us to 'shut it in' or 'curtail it back.' We noted earlier just how small of a component the compression fee is as a percentage of gas sales price or the movement of hydrocarbons, LOE expenses, etc. It's a relatively small percentage. Thus, the people that get hurt in downturns like this tend to be the E&P focused, commodity price guys, drillers, frackers, and pressure pumping guys. We tend to be a little more price elastic with the types and the duration of the contracts we see. When we discuss pricing concessions, our fixed component and amortization component are set up alongside our variable cost components. Typically, we try to offset any variable costs that we might cease to incur when units go on standby for a short period of time, which is typically a month or more. It's not hugely material and again tends to be relatively short cycle.

We'll go next to Praveen Narra with Raymond James.

And I apologize if I missed this. But first, thank you very much for providing guidance. Can you give us a sense for the embedded guidance, what kind of utilization you're looking for and how that compares to today?

Yes, Kevin, we don't provide specific utilization guidance. Our approach to the guidance revision was based on insights gained over the past few months regarding stop notices and standby actions. We considered this more as an assumed utilization and evaluated it nearly on a unit-by-unit basis. In response to TJ's earlier question, we are likely experiencing a 7% to 8% reduction in utilization. We haven't hit that level yet, but that's why we took a unit-specific approach, with the understanding that we can adjust it as the year progresses.

Right. Okay. And then if I could understand the standby process a little more. It doesn't sound like your contracts have defined standby terms in them, and that is more of a negotiation. Is that the correct way to interpret it? Or are these largely happening on the month-to-month contracts or month-to-month units that are out there?

Yes, Praveen, it's Matt. Typically, our contracts include a standard standby rate around 75% of the base rate. At that level, as Eric mentioned earlier, you're earning your gross margin, or even more in many cases, without incurring all the related expenses. That's generally how we've structured it.

No, that's super helpful. And if I could just squeeze one more in. You mentioned the number of units contracted on a month-to-month basis. Can you provide a sense of how much of your units come up within the next year and how we should think about that?

Over the next year regarding the month-to-month transition, I cannot provide an exact number. Historically, we have maintained a month-to-month range of about 40% to 50% for over seven years. Since the CDM acquisition, we have worked hard to term up, which has brought us down to approximately a 35% month-to-month range. Given the current market, I wouldn't be surprised if that figure increases slightly, as we aren't seeing strong demand for term contracts at the moment. However, in six months, the market conditions may change significantly.

Yes, Praveen, this is Eric. The reason I went off of my physics discussion in the middle of the discussion was to illustrate the stability of this big horsepower business. These machines are designed to have six to ten machines on a location. We may be moving 100 million to 200 million cubic feet a day. When you look at where these facilities are installed, these are regional hubs with lots of production feeding into these areas. It's not just a well or a pad site; it's major gas handling facilities. Even in the Permian and Delaware Basin, these facilities were installed four, five, six years ago. We're beyond the flush production stage. These are currently operating on cycle projects with relatively stable volumes. So to the extent there's no new drilling activity or if drilling activity declines, the volumes will continue to decline slowly, but the reservoir pressure will also decline slowly and methodically. That will require more horsepower. We can often get caught up with short-term contracts, that commodity prices are down, and volumes are declining without new drilling activity. Yes, that's true, but that drives our growth model, not our stability model. In today's environment where new activity has slowed down, volumes might decline, and pressures decline, to maintain the same volumes moving or even to manage declining volumes as pressures decline, the horsepower stays the same or might even tick up a little bit. That's why we are much more optimistic about our model compared to the small wellhead guys or even others who have jumped into large horsepower more recently. They may have a couple of units here and there, but we have the mega facilities with the extra-big horsepower which are major gas-handling projects and are there for the long-term duration. People that have commodity hedges in place. They also have firm transportation agreements in place. Major oil companies may be backing off on new growth CapEx, but they're still spending some growth CapEx and continuing to move base hydrocarbons.

And there are no further questions in queue. I'd like to turn the conference back over to Mr. Eric Long for any additional or closing remarks.

Well, thanks, operator. With the solid first quarter behind us, we are navigating through some uncharted waters right now. There are many things we do not yet know regarding how exactly things will shape up, but the industry and our customers have always been able to adapt to changing environments. Our business is built on natural gas demand, and we believe that positions us well for an eventual recovery. We believe that both the underlying stability of our large horsepower infrastructure-focused contract compression services business model and the science behind the need for compression in the interplay between pressures and volumes will be a key point of positive differentiation as we work through this downturn. We will continue to keep our focus on the things within our control, including prudent capital spending and cost controls throughout the organization. While we are hopeful for a recovery sooner rather than later, we have taken the necessary actions to weather the storm and come out on the other side. From past downturns, we have learned that we have many levers we can pull if and when we need to, depending on how this downturn plays out. Thanks for joining us, and please be safe. We look forward to speaking with everyone on our next call.

And that concludes today's conference. Thank you for your participation.