USA Compression Partners LP

Good morning. Welcome to USA Compression Partners LP's second quarter 2020 earnings conference call. During today's call, all parties will be in a listen-only mode, and following the call, the conference will be open for questions. This conference is being recorded today, August 4, 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 June 30, 2020. You can find our earnings release as well as recording of this call in the investor relations section of our website at usacompression.com. The recording will be available through August 14, 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 in this call speaks only to managed views as of today, August 4th, 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. Also with me is Matt Liuzzi, our CFO. This morning we released our financial and operational results for the second quarter of 2020, achieving a solid quarter of operational and financial results, especially when you consider the market environment in which we found ourselves. Similar to last quarter, Today I plan to briefly highlight the quarterly results and then spend more time discussing our business model, what we have seen happening out in the marketplace, and what we are doing to manage the business in this uncertainty. The second quarter, not surprisingly, saw decreased revenues as a result of customers returning equipment and a slowdown in unit redeployments out in the field. Total revenues were $169 million, approximately 6% below Q1. However, Due in large part to cost-cutting measures taken in late Q1 and early Q2, adjusted EBITDA for the second quarter was approximately $105 million, representing less than a 1% decrease from Q1. Reflecting this focus on cost, both adjusted gross margin and adjusted EBITDA margin were very strong at 70.4% and 62.5% respectively. Average utilization throughout the quarter was 88.0%, down from the Q1 levels of 92.5%, reflecting continued returns of units throughout the quarter. We ended the quarter with approximately 3.1 million active horsepower, which is off about 6% from the end of Q1, while the total fleet remained consistent at about 3.7 million horsepower. Average pricing across the fleet decreased slightly during the second quarter, which reflected the return of a fair amount of small horsepower which typically earns a higher dollar per horsepower rate as well as the impact of selective temporary service rate decreases. Average monthly revenues of $16.79 per horsepower was down slightly from $16.89 in the first quarter. Last quarter, we discussed revising the capital spending plan and we saw some impact of that decision in the second quarter. were growth capex consisted of $22.8 million and maintenance capex was $4.4 million. The growth capex included delivery of 16,700 new horsepower, of which about 75% consisted of large horsepower units. This growth capex had largely already been locked in by the time we had the events of early March. We do plan to see a meaningful reduction in growth capex for the balance of the year, which is unchanged from the previous quarter's commentary. Maintenance capital was also down versus Q1 as we limited spending given the slowdown in activity. At this point in time, we expect expansion capital spending to total between 80 and 90 million dollars, consistent with our guidance from the last call, which is compared to initial guidance of 110 to 120 million dollars. Based on the second quarter's results, the board decided to keep the distribution consistent at 52.5 cents per unit, which resulted in a distributable cash flow coverage ratio of 1.1 times X, which was up slightly from Q1, primarily due to a reduction in maintenance capital spending in Q2. Our bank covenant leverage ratio was 6.4X 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. I continue to be proud of the dedicated men and women of USA Compression who worked hard throughout the second quarter to deliver to our customers the services they rely on to successfully operate their businesses. Obviously, day-to-day life has changed a lot during this past quarter and how the future plays out is anything but certain. But in the face of all this uncertainty, our dedicated field technicians and everyone else who supports them figured out how to make it work and continue to do so every day in a safe operating manner. Let's talk a little bit about natural gas and crude oil. Last quarter, I spent some time on the different market dynamics between crude and natural gas and why we felt that USA Compression was well positioned to be somewhat insulated from the dramatic price volatility and uncertainty around crude oil, as our business is driven by the demand for natural gas. At the time of our last call, crude was trading around $20 a barrel. Since then, it has seen a bit of a rally to the $40 barrel range and has shown relative stability. Even with that rebound, many E&P companies are being cautious on capital budget. That makes for a challenging environment for companies that depend on new crude drilling oil activity, and you're seeing the fallout in bankruptcy filings. We are fortunate that our business is driven by the demand for natural gas. While we continue to take a long-term view of the overall need for and production of natural gas, even the near-term outlook has shown signs of relative stability during the industry weakness and strength in the medium to longer term. We continue to believe that natural gas will play a more and more important role as a clean fuel of choice. Now to the energy markets. It has been quite a ride since we announced first quarter earnings in early May. As the pandemic has continued to play out around the world, demand has been impacted both on the oil and natural gas side. However, as economies began to open back up, In May and since, oil demand has started to rebound. June saw global consumption of petroleum and liquid fuels up 10 million barrels per day versus May. Right now the EIA is forecasting 2020 consumption to be about 93 million barrels a day, which is only about an 8% decrease from 2019 levels. The demand destruction, which was previously forecast to be much more severe, seems to have moderated and we've seen crude prices hold relatively steady above $40 per barrel. As previously mentioned, even with the strengthening of crude oil prices, many of the E&P companies have held the line on reduced capital budgets, showing a level of discipline that we haven't necessarily seen in past downturns. The total rig count is down approximately 70% since the beginning of the year. Well, just in the last week or so, You've seen a rig or two get added in the Permian. Many expect the reduced count to last for considerable while longer. That should help support crude oil prices as economies recover and the demand continues to tick upwards. While it is too early to know what capital budgets will look like for 2021, I think it's a fair assumption that overall production growth will be less than we've seen in the past years. and over the coming quarters, we will see even more evidence of steep shale well declines in the early years of wells life. As I've discussed before, shale type curves, while steep at first, after a few years tend to flatten out significantly when a given well moves into more of a steady state existence. So if the CapEx cuts hole, producers will simply not be drilling enough new wells to offset the decline of their existing flush production wells. And then over time, you'll have a large amount of wells in that flat, steady state part of the curve where decline has also meaningfully slowed. While impacting production growth for the EMPs, this is a favorable situation for USA compression. 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. But as you all are aware, USA Compression doesn't move crude oil. We deal 100% with natural gas. The overall prospects for crude oil impact many of our customers, particularly in regions with significant associated gas. Because of the reduction in crude oil production, you are seeing a related decline in associated gas production, although generally not quite as severe as previously expected. Earlier, I mentioned how natural gas demand destruction wasn't nearly as bad as that for crude oil. In fact, while the demand was projected to be lower, what we've seen so far is even more positive than most have predicted. We've always believed that the resiliency of natural gas demand was one of the primary factors underpinning USA Compression's business model. Natural gas simply is a preferred fuel for its two largest end uses. residential and commercial power generation, and industrial manufacturing. While there is expected to be some short-term demand destruction, the EIA is currently projecting natural gas consumption to decline by about 3% in 2020. The underlying demand for natural gas remains strong. While generally things have stabilized for the midstream sector, the capital budgets of the E&P companies remain dramatically reduced from where they were at the beginning of the year. So what does that dynamic mean for USA compression? I often discuss the relationship between compression horsepower and declining reservoir pressure. Simply described as pressures decline to move the same volume of gas requires an exponential increase in compression horsepower. As an analogy, think about a fully inflated bike tire. When you take off the valve cap, air whooshes out of the tire very quickly at first, but then slows quickly. Wells are not that different. This concept underlies the reason why compression is not transactional, like a typical oil field service company. Drill the well, complete it, then move on. Instead, compression stays around for a long, long time, but that whoosh of oil and gas slows down and ultimately needs more effort, i.e. horsepower, to get it out. For both associated gas and dry gas applications, even though gas volumes may be declining, The compression required may actually increase as pressure also declines. You've also heard a lot about gas-oil ratios, which in many cases have increased as producers have moved beyond core areas, as increasing gas-oil ratios have led to more associated gas production. Per barrel of oil produced, you will need additional compression to move those volumes. These concepts underpin the compression services model that USA Compression is based on. When markets are great, we grow with our customers. Over our 22 years in business, we've been through multiple cycles. During periods of reduced activity and even production declines, we have not historically experienced material declines in the need for our large horsepower compression services or required horsepower. The dynamics I've mentioned above, along with relatively resilient demand, have historically made large horsepower compression a less volatile business. As we mentioned on last quarter's call, the natural gas markets are expected to experience a fairly unique dynamic in the near-term future as the relatively resilient demand outlook intersects production declines, notably from associated gas regions. You are already seeing consumption tick back upwards while supply begins to decrease. For example, Mexican exports in July are at record levels, averaging about 6.1 BCF per day, up some 13% from year-ago levels of about 5.4 BCF a day. LNG exports, however, have been a little soft, and for July averaged about 3.2 BCF per day, down about 24% from year-ago levels of about 4.1 BCF per day. In the near term, that oversupply has led to higher than expected underground storage levels, but as we get through the summer and into the natural gas withdrawal season, we may very well may see a more strained supply-demand balance because of the decrease in new well drilling and the dynamics of the shale-type curves really adding some pressure to the supply side of the equation. Natural gas futures prices for calendar 2021 are averaging around $2.50 per MCF. As it regards the markets, obviously the sooner-than-expected rebound in crude oil prices and relative stability in both crude oil and natural gas bodes well for the broader energy industry. And the resilient demand on the natural gas side bodes well for critical service providers like USA Compression. As natural gas continues to play a very important role in this country's energy future, we are optimistic about the future outlook for the compression business. So let's talk about our large horsepower focus. Over the 22 years of USA Compression's existence, our business model has not changed. We have always focused on larger horsepower compression used in large, regional infrastructure-oriented facilities. The rationale behind this strategy has been proven after in previous downturns and simply comes down to the fact that these facilities move very large amounts of natural gas and are demand-oriented. We have purposely pursued the large horsepower, and because these facilities are not easily shut down, and the costs of demobilization which are borne by our customers to send home our assets tend to be extremely expensive. This creates a barrier to exit which lends stability to the business that other service providers, both in compression as well as activities closer to the wellhead, do not possess. We have always pointed to the stability of this business model and as we work through the remainder of 2020, we expect to experience that relative stability. A little bit on our customers. Based on customer activity and indications, we are currently expecting utilization to bottom out in the third quarter. At June 30, our utilization stood at 86.2%, which was similar to where fleet utilization declined back in the 2014 to 2016 timeframe. Remember that crude got as low as $27 per barrel back then. While it went lower back in March of this year, it rebounded much more quickly and has stabilized. and so while the recent quarter or so is somewhat different from the 2014 cycle, our customers have behaved in a similar fashion. We have seen the rate of return of underutilized assets decrease meaningfully. We have seen recent code activity pick up substantially and have had equipment starts begin to once again outnumber equipment stops. We continue to see the large horsepower equipment classes remain utilized proving the strategy of pursuing larger infrastructure-based applications. Overall, our customers are working to figure out what the future holds for their particular operations as well as the overall industry, and that creates different motivations for different customers in different bases. The vast majority of our assets serve either dry gas activities and natural gas handling activities such as those connected to gas processing plants or large volume centralized gas lift applications beyond the flush production stage and in the stable, shallow decline, steady state mode. With the geographical diversity of our asset base, we have exposure to different producing regions, and as such, have a balance throughout the fleet. Events in one particular area, like associated gas declines in the Permian and Delaware basins, while they affect us, are partially mitigated by activity in other regions like Appalachia. I've mentioned before our contract mix and how historically we had anywhere between 40 and 50 percent of our assets out on a month-to-month basis. As a result of re-contracting activities over the last year or so, we have reduced our month-to-month exposure to approximately 26 percent, which puts us in a good position as we work through the rest of the year. We have new starts of equipment scheduled for the back half of the year. So that will add some additional term contracts to help mitigate some of the month-to-month units that have come home. While the industry as a whole is by no means out of the woods and onto recovery, we believe you are beginning to see signs of a bottom and indications of recovery. While we saw a fair amount of unit returns during the second quarter, the rate of unit returns has slowed appreciably, and as a result of our cost-cutting and capital spending decisions, We believe the company is positioned to weather any additional market softness and emerge in a position to benefit from what we believe will be an eventual recovery. As many appreciate, our focus over the years has purposely been away from activities that introduce commodity price risk and oriented toward larger installations serving demand-driven natural gas infrastructure applications. We have deployed significant amounts of capital, excuse me, significant amounts of horsepower in large multi-unit centralized compressor stations over the recent years. These installations are critical to serving the resilient demand that I discussed earlier. The production in many cases has moved into the steady state phase with shallow decline rates, thereby reducing relatively more stable volumes and pressures. As these wells age and the 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?