USA Compression Partners LP (USAC) 2016 Q1 法說會逐字稿

Good day, everyone, and welcome to today's USA Compression Partners first quarter earnings call. (Operator Instructions)

Please note this call is being recorded.

It is now my pleasure to turn today's program over to Greg Holloway, Vice President, General Counsel, and Secretary. Please go ahead, sir.

Thank you, Priscilla. Good morning, everybody, and thank you for joining us.

This morning, as you know, we released our financial results for the quarter ended March 31, 2016. 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 16.

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 latest filings with the SEC.

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 Chief Executive Officer of USA Compression.

Thank you, Greg. Good morning, everyone, and thanks for joining our call. Also with me is Matt Liuzzi, our CFO.

This morning, USA Compression released our first quarter 2016 financial and operational results, and I am pleased to report that we started off 2016 with a solid quarter of performance against a challenging market backdrop, demonstrating the continued stability of our compression services business model.

For the first quarter, USA Compression reported moderate year-over-year increases in revenue and adjusted EBITDA, while distributable cash flow, or DCF, grew 8% relative to Q1 2015.

For the last several months, we've been in the stability phase, and our results for the quarter demonstrate that. For the rest of the year, we expect to continue to focus on stability and positioning USA Compression for what we believe will be the inevitable upturn in the energy space.

While there remains still some uncertainty in the market and participants, including ourselves, are taking a cautious approach to full-year expectations, I want to highlight a few things that reinforce the critical nature of our services and illustrate our continued focus on maintaining a sound capital structure.

First, the Permian and Delaware basins continue to be active. This area has clearly become more and more prominent within the industry, and we remain very active in those areas.

The northeast infrastructure build-out continues, with major players embarking on major projects. This has been and continues to be a core area for us.

We recently amended our credit facility to give us room to operate and make prudent financial decisions for the long term. Coverage and leverage continue to be a focus, and Q1 reflects attractive levels on both those metrics.

And finally, we kept the distribution flat, providing unitholders with attractive yield while not stressing the partnership's financial position.

These results represent a good start towards our previously stated 2016 outlook, which we again affirm. As in the past, we will continue to provide updates to our guidance throughout the year, both financially and operationally.

In keeping the distribution flat, our coverage ratio for the quarter was 1.1x, and our leverage remained at check, at 4.8x. We continue to heed the message from investors of the growing appreciation for a strong balance sheet and coverage relative to distribution growth in the current environment.

Also during the quarter, we successfully amended our credit agreement with our bank group. Matt will provide more details on the amendment and the leverage covenant flexibility it provides in a bit.

Recently, the price of our common units has recovered from the low $7s to the mid-teens level. This behavior suggests that even though roughly 85% of our assets are deployed in demand-driven natural gas infrastructure applications, our units appear to trade with a close correlation to the price of oil and its outlook. We continue to believe that over time our investor base will see that it is the demand for natural gas -- which continues to grow -- that drives our business and not the spot price of oil.

As I've mentioned before, our business model is characterized by both and stability and growth over the course of multiyear commodity cycles. While we spent the last several years in the growth mode, taking advantage of market-driven demand for natural gas and attractive capital costs, we are now focused on the stability of our infrastructure-oriented asset base.

Given the critical nature of our assets in the overall natural gas infrastructure, we have been able to hold utilization and pricing close to historical averages.

While we have seen and may see some continued small decline in utilization, remember that existing gas production still requires compression to move it through the pipeline system. Even in areas where overall volumes are flattening or entering the steady-state decline mode due to lack of incremental drilling, well pressures can also decline significantly, which means compression requirements could actually increase over time to move that same volume of natural gas.

As most are aware, the majority of our assets are infrastructure-oriented and are tied to the production of natural gas, which in turn is driven by increasing demand, which in turn has resulted in fairly stable pricing and utilization. This is especially true when compared to drilling-oriented oilfield services businesses whose utilization, pricing, and revenues may be off 40%, 50%, or even more in a downturn like the one the industry is currently in.

As I mentioned previously, both our pricing and utilization were down just slightly quarter over quarter. But as natural gas production and demand continue to grow, we expect continued demand for our services.

As we discussed before, our infrastructure-oriented equipment is critical to the natural gas value chain. And as producers and transporters of natural gas work to optimize their own production and transportation volumes, that is naturally going to impact our business.

With the lower commodity prices experienced earlier in the year, our customers were forced to continue to examine their own operations. And as a result, we saw a slight degradation in our utilization rates over the last three months, with an average of 88.7% in Q1, relative to 89.5% last quarter. All told, not too bad considering the market environment.

Customers in all regions continue to reexamine their capital budgets and related future compression requirements, as well as optimizing their existing compression needs, especially as overall volumes in certain areas continue to flatten or have entered the shallow decline phase of shale production.

However, we continue to see pockets of activity in the northeast, as well as west Texas, particularly on the Delaware Basin side, and we continue to put equipment into service with financially stable counterparties at attractive economic returns.

As we discussed last quarter, our management team is laser focused on pulling the various levers we have at our disposal, and maintaining utilization remains a top priority, while doing so with service fees that justify the work that we're performing.

When coupled with the high barriers to exit we have touched on in the past -- including direct costs borne by our customers associated with freight, cranes, and demobilization, as well as certain permitting requirements -- we should be able to keep our compression assets deployed and active, as our larger horsepower gizmos remain in relatively high demand across the industry and from our customers, resulting in relatively stable utilization rates and cash flows for our investors.

Additionally, we believe as the market sees stability in commodity prices, we will begin to see stabilization in activity levels across all basins and a return to producers and midstream operators embarking on new development plans.

On the pricing side, we saw a slight decrease of approximately 1.5% from last quarter for the overall fleet; of that, the majority of the decrease related to the gas lift small horsepower side of the business, which, as a reminder, represents only about 15% of the total fleet horsepower. These units are more tied to the production of crude oil. And as the price of crude has fluctuated, our customers have worked to keep their operating expenses low. We have continued to work with our customers to develop win-win situations where we can both benefit from the relationship over the long haul.

Given both the critical nature of our larger-horsepower, midstream compression assets, which are utilized in transporting large volumes of gas, as well as the longer-term nature of contracts for larger horsepower, we generally see more stability in rates related to midstream infrastructure applications.

Service rates for new projects and installations can vary by operating regions. In areas of softness, there is clearly more price-based competition for customers, but we remain disciplined in our pricing to ensure that we continue to earn attractive economic returns in these areas.

In general, due to the high barriers to exit, we find that our compression assets, particularly on the large horsepower midstream side of the business, continue to be very sticky on both pricing and utilization, as well as staying in the field beyond the primary contract term.

While pricing and utilization are hard to predict in an environment like the one we're currently in, we believe that the infrastructure-oriented, demand-driven nature of our asset base is built for stability in times like these. During our nearly 20-year operating history, we've been through multiple commodity cycles and, while each is unique, our business has demonstrated stability in margins and cash flows.

We continue to proactively manage the business to focus on operational excellence and maintaining our fleet utilization through this downturn, while also directing our efforts at the other levers at our disposal: maintaining capital discipline and maximizing our operating margins.

As it relates to capital discipline, we spent a total of about $15 million of expansion capital in the first quarter of 2016, down drastically from the $115 million last year during the same period, and a majority of that spend reflects payments for prior-year equipment purchases.

We continue to expect to spend somewhere in the range of $40 million to $50 million for expansion capital in 2016, versus $270 million in 2015, a reduction of over 80%. We still expect just over 15,000 horsepower to be delivered this year, and at this time do not expect to make any additional commitments to purchase new units for the year.

We plan to fund our minimal capital expansion with operating cash flow and borrowings and plan to live within our current capital structure, aided by the flexibility arising from our recent credit agreement amendment.

As we have touched on in the past, relative to pipeline businesses with multiyear lead time projects with significant capital commitments to meet, our business has much more flexibility with regards to capital spending, and we have been able to quickly rein in our expansion CapEx. Given our extremely scaled-back fleet horsepower additions this year, equating to less than 1% of our total fleet, we will focus on utilizing our in-stock large horsepower equipment as new projects come about.

Finally, we continue to wring out operational and corporate efficiencies, as evidenced by our sustained high margins. Overall, gross margins were relatively flat quarter over quarter, at just under 69%. In particular, our gross margins on the contract compression operations remains over 70%, which represents the highest margins of our public peers even as pricing has ticked down just a bit.

Our operating team, which we believe remains the best in the business, continues to demonstrate operational excellence and ability to control cost. We remain laser focused on finding additional areas of savings.

We continue to be bullish on the long-term natural gas market domestically, and we are positioned to ramp up growth again when the market dictates. While current low commodity prices affects new drilling activity, we believe the overall gas supply picture appears to be robust in the future years. Part of the explanation for this is that producers continue to experience productivity gains and lower drilling and completion costs, all of which drive efficiencies.

Recently, we saw the natural gas strip prices exceed $3 in early 2017. We believe this level of prices, if sustained, could spur development of new or delayed upstream and midstream natural gas projects, particularly in the prolific Marcellus and Utica shales.

On the oily side, as we have mentioned, we see continued activity in west Texas, particularly in the Delaware Basin. Given the stacked horizontal potential in these areas, E&P operators are still able to earn attractive returns on incremental drilling and new production. Pioneer, one of the top acreage holders and producers in the Permian and Delaware basins, recently stated that they would add five to 10 additional rigs in the area when oil recovers to approximately $50 per barrel.

We expect that natural gas demand growth will continue to be driven by the same factors we have touched on in the past, including: ongoing, large-scale coal plant retirements mandated by EPA regulations; continuation of growth in LNG exports; increasing industrial demand, driven in part by new petrochemical projects under construction; and pipeline exports to Mexico.

In fact, Mexico has begun to see its own domestic gas production fall, and those declines are only expected to accelerate. This should further boost US gas exports to Mexico, which were up 40% year over year in March, to around 2 BCF a day.

This expected continued increase in domestic natural gas demand will drive increased infrastructure investment, of which compression will be an important part. Recently, INGA, the Interstate Natural Gas Association, updated its report on long-term infrastructure spending. And while the headline was that estimated spending was down slightly, the aggregate numbers remain somewhat staggering: approximately $550 billion of investment through 2035, or about $26 billion per year.

Closer to home for USA Compression, INGA further estimates a need for about $23 billion to $30 billion of compression for gas gathering lines over the same period, which corresponds to well over $1 billion of projected compression investment annually. The report also indicates that a significant amount of the required midstream development is expected to occur by 2020, driven by the growth in cost-effective shale production and demand factors such as LNG and exports to Mexico.

As the report clearly indicates, natural gas is and will become more and more important over the coming years, and compression remains a critical and essential part of the overall natural gas infrastructure investment.

I'll wrap up my comments by reiterating our strategy to manage through this current trough in the latest energy cycle: rein in gross spending and live within our capital structure; focus on maintaining high fleet utilization by providing superior levels of service to our customers; and wring our cost savings throughout the organization.

We continue to prove out the stability of our business model, which focuses on critical infrastructure and must-run compression equipment, while also remaining flexible to efficiently respond to changing market conditions. We remain bullish on the outlook for compression over the long term, given the attractive macro fundamentals for growing natural gas demand and continued infrastructure build-out. Our large horsepower business model and stable cash flows all set USA Compression up for future success and long-term sustainability.

I'll now turn over the floor to Matt, to cover some of the financial highlights of the quarter. Matt?

Thanks, Eric, and good morning, everyone.

As Eric mentioned, USA Compression reported another very strong quarter of operations against a tough market backdrop. For the first quarter of 2016, USA Compression reported revenue of $66.4 million, adjusted EBITDA of $38.4 million, and DCF of $31.9 million.

In April, we announced a cash distribution to our unitholders of $0.525 per unit, which results in a DCF coverage ratio for the quarter of 1.1-times. Taking into account the impact of the DRIP program, our cash coverage for the quarter was 1.68-times.

With the support of our largest unitholders, we continue to strike a balance between the DRIP and cash pay distributions. This quarter, Riverstone elected to take 20% of its distributions in cash, joining Argonaut Private Equity who elected to go all cash pay.

By methodically working our way towards less reliance on the DRIP program, we believe we can maintain critical financial flexibility in this market while advancing towards the ultimate goal of eliminating our need for the DRIP.

In Q1 2016, we continued our trend of reining in our capital spending, investing only $15 million of expansion capital, a majority of which was related to equipment taken delivery of, but not yet paid for, by year-end 2015. In fact, we did not take delivery of any new compression equipment in the quarter.

Given that fact, we ended Q1 similar to where we ended 2015, with just over 1.7 million total fleet horsepower. Our revenue-generating horsepower at period-end was essentially flat relative to Q4, at 1.4 million horsepower.

We continue to focus on working off the backlog of 2015 deliveries yet to be placed into service. While we invested a total of almost $270 million in expansion capital in 2015, as Eric mentioned before we expect to spend considerably less than that in 2016, somewhere between $40 million and $50 million. We continue to expect to take delivery of only 15,000 horsepower in 2016, primarily in Q2 and Q3. The remaining expansion capital will be spent on certain compressor package components, equipment reconfiguration, IT infrastructure, trucks, and other items necessary to support the business.

Our average horsepower utilization for the first quarter was 88.7%, down slightly in sequential quarters from 89.5% and down from 91.9% in the first quarter of 2015.

Pricing, as measured by average revenue per revenue-generating horsepower per month, was down slightly, to $15.72, from $15.97 in Q4, and down from $15.85 year over year.

Turning to the financial performance for the first quarter, total revenue increased 2.1% compared to the first quarter of 2015, primarily driven by an increase in our retail and parts revenues. Our revenue from contract operations was up slightly year over year.

Gross operating margin as a percentage of revenue was 68.6% in Q1 2016, down relative to Q1 2015, partially due to higher parts and services revenue which tend to earn lower margins than our contract compression operations.

Adjusted EBITDA increased approximately 2.4%, to $38.4 million, in the first quarter, as compared to $37.5 million for the first quarter of 2015.

DCF in the quarter was $31.9 million, as compared to $29.5 million in the same period last year, an increase of approximately 8%.

Net income in the quarter was $8.5 million, as compared to $11.5 million for the first quarter of 2015, a decrease of roughly 25%.

Net cash provided by operating activities of $22 million in the quarter increased 51% relative to $14.5 million in the same period last year.

Operating income decreased 11%, to $13.8 million, for the first quarter of 2016, as compared to $15.5 million for the first quarter of 2015.

Maintenance capital totaled $1.4 million in the quarter, which was consistent with expected levels for the quarter, as we accelerated certain maintenance activities into Q4 2015. We continue to expect approximately $15 million of maintenance capital in 2016.

Cash interest expense, net, was $4.6 million for the quarter.

Outstanding borrowings under our revolving credit facility as of March 31, 2016, were $743 million, resulting in a leverage ratio of 4.8-times at quarter-end, the same level that we reported at year-end 2015 and well within our covenant level of 5.5-times.

As Eric mentioned, in March we successfully amended our credit facility, which allows for leverage ratio covenant relief beginning in the second quarter through 2017. We believe this amendment provides us with increased flexibility in managing our balance sheet, leverage, and distribution policy and that it reflects the continued strong show of support by our lender group.

As it regards full-year 2016 guidance, at this point in the year we are affirming the ranges that we previously provided: full-year adjusted EBITDA of $138 million to $153 million and DCF of $102 million to $117 million. As everyone on this call can appreciate, we are still relatively early on in the year, and as the year progresses and we gain more clarity around trends in utilization, pricing, and margins, we expect to be in a better position to provide updated guidance.

Finally, we expect to file our Form 10-Q with the SEC as early as this afternoon.

And with that, we'll open up the call to questions.

(Operator Instructions) Praveen Narra, Raymond James.

So, you guys had mentioned that the majority, or a decent portion, of the utilization decline has come from the gas lift side. I guess, if we could separate the natural gas levered compression versus the oil levered compression, could you give us a sense of what you're seeing on the utilization and pricing side on just the gas levered portion?

Sure, Praveen. And I think it's important to remember we don't actually separate those out, but we'll try and just give you some color for how the different segment businesses are performing.

Most of the decline is on the gas lift side of things. Obviously, that's -- for our business it's tied to people drilling oil wells. And so, as you saw the price of oil kind of go up and down over the last quarter and even beyond, that's where we've seen the volatility in both the pricing and just overall utilization.

The utilization on that side of the fleet is going to be significantly less than on the midstream side, and that's just the nature of those units, the nature of the contracts. When you compare it to the midstream stuff that's three- to five-year contracts, inside houses, infrastructure, large compressor stations, contrast that with the gas lift side of things which, as the price of oil goes up and down, these operators are making decisions on a daily basis.

So, that part has certainly been lower than on the gas midstream side of things, and pricing has reflected that. It's obviously more competitive out there for those units, and stuff that's on six-months, one-year contracts is going to come up for renewals more frequently.

But overall, I think as we've said in the past, we've been, I think, pleasantly surprised at how resilient that side of the business is. It obviously is a different business than the midstream natural gas side of things, but has still proven to be, I think, more resilient than we thought.

Okay. That's helpful. It's nice to see the reaffirmed guidance. I guess, could you give us a sense of what kind of utilization is being -- that guidance is predicated on? And then, if you could, what you've seen thus far into 2Q?

Sure. I think looking out over the full year, as we kind of do our internal forecast, we take a fairly conservative route. I don't think we disclose exactly what the utilization we assume is. But as we have visibility for units coming and going, we bake that into our forecast. And I think we are -- our forecast, we're sort of prepared for a continued more of the same, I think. And so, the utilization would reflect that.

But again, we look at our fleet, and 85% of it is midstream based and it's long contracts and it's stuff up in the northeast and west Texas where there's a lot of activity. And so, that kind of stuff, it's not like that stuff just comes home. It's longer-lived stuff and with good contracts. And so, because of that, we think that part of it really holds up well.

And so, we'll continue watching the utilization as it goes on, but it's not --. I don't think we're projecting a huge increase in it, but we're also not projecting a fall off the cliff.

This is Eric. Let me chime in with one other kind of overall macro. With 85% of our assets being deployed in infrastructure midstream type applications, there's a lot of both shale gas that we've been involved with in multiple basins for an extended period of time. In some of these basins where you've got dry gas shale production, new activity ceased or slowed down significantly two or three years ago.

And if you look at the hyperbolic nature of declines from shale wells, you have big volumes and flush production for a year, 18 months, 24 months. Then, you go into the shallower, almost steady-state mode on the back end of the tail, post the flush production from the shales.

So, a lot of our assets are deployed in areas where the, quote, slowdown occurred two, three, four years ago and, attendedly, we're now seeing moderate to very shallow declines in some of these areas.

The other thing that we see is we'll have multiple units on an installation. We don't have one compressor; we might have eight or 10 or even 12 on a big pad site. And to the extent that the flush production has backed off, needs have declined a little bit, you might see one or two units of ours get sent home.

And then, you go into this relatively shallow decline mode, pressures decline, and we end up seeing the balance between volume and pressures, which mandate that the compression that once the flush production is gone tends to stay there and it's sticky for an extended period of time.

So, our business model and the type of assets we have are very different than the vast majority of our peers, public and private alike, and it allows us to have that stability of cash flow, stability of distributions for the long haul.

So, as you've heard me say before, we grow when it makes sense to grow. We stabilize and focus on the stability side of the model in times like this, which are just kind of the basic physics of how the natural gas flows. We're now in a lot of our installations in that steady-state mode, with shallow to no decline.

[And I think that's showing up]. Great job, guys. Thank you.

T.J. Schultz, RBC Capital Markets.

Eric, just kind of following up on that last line of thought, I want to touch on one thing you mentioned in your prepared remarks. When we think about midstream larger-horsepower applications, you stressed the high barriers to exit. If you could just expand on that as we think about the costs, whether cash costs or opportunity costs, that your customers consider that make those exit barriers real?

Sure, T.J. When you think about one of our bigger machines, a Caterpillar-driven 3608, which is about 2,500 horsepower, this guy weighs somewhere in the range of 250,000 pounds. It's going to be the size of roughly four diesel locomotives. So, they're really big gizmos. Many of these types of units are located inside of buildings.

So, you can imagine the cost required to dismantle a building, to bring in very large cranes to dismantle our pieces of equipment into four or five different groups; coolers separate from the compressor skid, separated from the engine skid, as an example. You have to put this on trucks that are then used to haul the equipment back to a central freight site; in many cases, Oklahoma or Houston. So, you may be talking as much as $100,000 of demobilization cost per piece of equipment.

So, if you think about the applications of this, we've got large volumes of natural gas moving through our facilities. You've got this $100,000-ish cost per machine to send it home, and you might have eight or 10 machines on a location. So, you're talking numbers that are $500,000 to $750,000 to $1 million to demobilize stuff. And I think our operators look at that and go: Do we really want to send this type of equipment home?

In the low commodity price environment, we've seen installations where our customers have curtailed natural gas production. Instead of producing at the wells wide open, they might throttle them back 50%. Well, clearly, they're not going to spend CapEx dollars or OpEx dollars that affect their LOE to send our equipment home, when they might in two or three months need to turn the wells back up again and flow bigger volumes.

In the case of customers that are having some financial difficulties, (i.e., a bankruptcy), the last thing they want to do is incur that additional $500,000, $750,000, $1 million to send equipment home and then be forced to spend that same amount of capital to bring new equipment in or replacement equipment in that's going to be market priced, effectively the same type of rates that we're seeing today.

So, once this stuff is installed, unlike the small wellhead either gas lift or dry gas well equipment, this stuff sits there for the long-haul duration because of those barriers to exit, T.J., that you pointed out. It's expensive to move this stuff.

Okay. Thanks. That's helpful. Matt, maybe, on the debt amendment, is there any change to the pricing grid in exchange for the covenant relief?

No, there was no change to pricing or anything else; just purely those leverage covenants.

Okay. Great. Just lastly, obviously this week we saw another compression MLP cut distributions. Ultimately, it's shaken out to be well received by the market, relatively speaking. So, I guess just a question is, does that adjust at all your thinking on distribution policy as you balance distributions at the same time as managing leverage?

I'll jump in, T.J. Interesting announcement, and I guess that's why we leave it to you guys to pick the stocks.

But overall, we talk about it every quarter with the Board. It's their decision. Obviously, we looked at this quarter, and several weeks ago when we made the announcement, we knew the performance we had for the quarter and we thought the right thing to do was to return capital to the unitholders.

With this credit facility amendment and kind of our business, the line of sight that we have on it, we like the position we're in right now. Obviously, we can't speak to kind of what others were seeing or had to or didn't have to do. But it's a discussion that we're going to have every quarter, and it was an interesting market data point.

T.J., from my perspective, our business model is significantly different than that of our peers: the bigger horsepower, infrastructure-related equipment, the long-term contracts -- versus short cycle time, high beta, older vintage equipment with zero barriers to exit.

And just even from a simple productivity stance, if you were to look at DCF per employee, USA Compression is roughly $250,000 of DCF per employee. And a couple of our public peers are $100,000-ish or even as low as $50,000 to $60,000.

So, we're a much more efficient machine. We're a much more stable machine. And we obviously look at our distribution as something which our investor base has looked for the stability component of it.

As Matt mentioned, the Board makes that decision quarter over quarter. But our belief currently is we operate as an MLP, we need to reward our long-term-focused investors. To the extent we can continue to balance leverage and coverage and afford to keep the distributions as they are, that weighs on our thinking.

Okay. Great. Thanks. I appreciate the comments.

Andrew Burd, J.P. Morgan.

I had two kind of bigger-picture, more macro thoughts. The first is, over the last, I guess, 18 months, the industry has seen a pretty decent amount of compression taken out of service. When the cycle turns eventually, how much of that do you think is eligible to reenter the market? Or, said differently, do you see the industry's available capacity potentially shrinking?

A really good question. And I think you have to look at horsepower ranges. Over the last 18 months, the bulk of the degradation in utilizations has occurred either by retirements of old equipment that don't meet emissions standards or are fuel inefficient -- it's stuff that has been acquired through consolidation in the industry over the last 20 or 30 years and, frankly, is equipment that will never come back into play -- and there's also a fair amount of this small horsepower stuff that has very, very high beta directly tied to either natural gas commodity price, oil commodity price, et cetera.

When you look at the niche that we play in, the big horsepower range, there's not a lot of idle equipment laying around. If we go back and look at the 2008-2009 range, our peers developed somewhere between 500,000 to 750,000 horsepower of the big stuff like this that was sitting around idle.

We're in a very different environment today. There's not a plethora of equipment of this big horsepower range laying around idle.

So, my own personal sentiments are is when the inevitable upturn occurs, there's going to be a lag time between the timing to build new equipment -- for Caterpillar to ramp up, Ariel to ramp up, and others to ramp up -- and that there will be some lag time when producers start to complete their drilled and uncompleted wells and start mashing the accelerator and increasing rig count, which should bode positively for the large horsepower compression sector.

So, understanding that correctly, thinking about that scenario, in the upside recovery those larger horsepower units may see a price response. Utilization is already tight. And the smaller units, you may not see the price response right away, because utilization is going to creep up first. Is that a fair way to think about the eventual recovery?

I think that's a fair way to look at it.

Okay. And then, the second question is, again a macro one, on the competitive landscape. We know about your public peers; so you don't have to necessarily comment on the big four. But I'm curious if you're seeing new entrants into the compression business, especially as you and your peers are reining in the horns? Or conversely, are you seeing smaller competitors exiting because they're feeling too much pain? And kind of color on the competitive landscape would be great.

There are a few private companies that are floating around out there, one or two -- one, in particular, with some size, a couple that are relatively new entrants which are relatively small players.

I think all of the folks are experiencing some balance sheet constraints. So, very few of the peers are aggressively deploying new equipment.

There is one new entrant that was recently backed by some private equity folks. So far, they're establishing some toeholds in some areas, actually developing more operating type services agreements rather than deploying a large amount of capital back into the industry.

So, it's one thing to have access to capital; it's another thing to have in place the MSAs required to do business with major oil companies and large independents, to have the safety programs, the training programs, the support infrastructure.

For a new entrant to get into the business, it takes a fairly significant lead time -- and I'm talking in five, six, seven years -- to be able to gain any traction. So, we're not seeing lots of new entrants into the industry. And in fact, it's fairly limited because of the magnitude of some of the things I've just suggested.

With some of the other private players, they're experiencing the same balance sheet limitations that all of us are in the industry.

I think the positive side of that is our customers, both midstream and E&Ps alike, are also experiencing balance sheet limitations. If you go back five years ago when there was, quote, unlimited capital available to our customers, some people made the decision that: Maybe compression is a core competency and something we should insource rather than looking to outsource to someone else.

Well, with constrained balance sheets, particularly the E&P guys are now looking at it, saying: I need to put what limited and precious capital I have into the ground to develop or I need to build a pipeline or I need to build a processing plant. I really don't necessarily need to own a big fleet of compression assets and the staff that goes with it and the training and the inventory and all the things that go along.

So, we actually, in an environment like this, start to see opportunities to pick up some incremental market share -- all of us in the industry do, my private and public peers alike -- because there's some incremental opportunities with folks who just a mere five years ago did things themselves, who are now looking to expand the outsourcing relationship.

That's some fantastic color. Thanks very much.

(Operator Instructions) Richard Verdi, Ladenburg.

Congrats on successfully navigating the Company through this rough environment and being able to reaffirm guidance here. That's great.

I guess my first question pertains to the amendment to the revolver. I'm curious if you could tell me the decision behind that? For instance, was it because maybe USA doesn't want to deal with the banks? Or, is it because maybe that the Company sees challenging times ahead?

Rich, we've been doing this a long time. We've worked with our bank group now for over a decade. Others in the industry have the ABL structure that's modeled around what USA has done for the past decade, or so.

So, we had some concerns about, coming into this year, what the E&P environment was going to look like. Were we going to be at $40 or $50 oil or were we going to be at $15 or $20 oil?

We proactively approached the bank and said: Guys, you've worked with us for a long time. We really don't think you want us longer term to be forced into an environment where we have to go raise equity at an absolute bottom of a cycle. That creates leakage for the banks. It creates leakage and overhang for all of our unitholders.

And because of the long relationship we have, the type of our contracts, the type of assets we have and how they're deployed, the bank was able to get very, very comfortable very quickly that, hey, we're probably never going to bump up on any of these covenants. But frankly, it was an insurance policy coming into the first quarter of 2016 not knowing what the world was going to look like.

So, I think now as we've powered through three or four months, we're starting to get better commodity clarity to the back half of the year. When you looked at the likes of Ray Jay and Tudor, Pickering who were projecting anywhere between $60 to $75 oil the back half of this year, there appears to be some optimism coming into the marketplace. The appearance is that we've kind of hit the bottom, we're now bouncing along the bottom a little bit.

So, again, we just wanted to be proactive, get ahead of the curve, get ahead of the bankruptcies, get ahead of the borrowing base redeterminations that were getting ready to occur in the energy patch, and just position ourselves that no matter what the commodity price environment did, we weren't going to bust a covenant. So, it was imply an insurance policy.

That's great. Thank you for that, Eric. And my next question pertains to the contracts. With what the Company is seeing right now, how much of this business would you say is under primary contracts versus month to month? And for the month to month side, do you feel it's because customers are afraid they might shut down? Or, is it because they realize they're capturing favorable pricing?

It's a combination. I would say that roughly 60%-65% of our assets are deployed under remaining initial primary terms, and we've got plenty of term under this. As you've heard me state before, our bigger horsepower typically goes out under contracts that have an initial primary term of two to five years. That's very different than the smaller horsepower equipment that might have six months or maybe, at most, a year or so.

What we do tend to see on bigger horsepower when it comes off of month-to-month contracts, we look at things like: Is it running loaded? Lightly loaded? What are the market conditions like? Are the rates at market? Are they above market? Are they below market? The last thing we want to do is look at reterming up on an extended basis our bigger horsepower assets at pretty low rates.

So, I think what we have seen over these various cycles over the almost 20 years, or so, is that, in an environment like we're in today, some of our producers and some of our customers would like us to term up things and, frankly, we kind of drag our feet and would prefer not to.

So, it's a balancing act. We look at portfolio management across our entire fleet, across all horsepower ranges. And we want to maintain some flexibility for the future, that when the inevitable upturn and what we anticipate to be some limited availability of equipment, that we can capture some of that upside ourselves rather than locking in at the bottom of a cycle today just for the sake of locking in some terms.

So, we try to balance all those things.

Okay. Thank you for that, Eric. And you mentioned a few times today the Company continues to see strength in the northeast and west Texas. And looking out over the next, let's say, one to three years, does USA expect that trend to continue? Or, could there be another location that could become more prominent to the Company?

Well, I think it boils down to access to capital and the economics associated with the opportunities. There are clearly basins and geography where USA does not have a footprint. Our customer list is significantly smaller than that of some of our peers. Our top 10 customers are a skosh under half our revenue, and our top 20 customers are 60%-65% of our revenues, or so.

So, there's plenty of opportunities for us to expand our relationships with additional customers, expand our relationship with current customers into different geographic areas, ability to expand into different basins where we don't have a presence or a foothold.

The bottom line, I think it's a function of the economics and what the market conditions look like. We have a history of growing organically, and to the extent those opportunities exist and the economics make sense and capital windows are open, we'll take advantage of those things.

Okay. Great. Great. And that actually kind of dovetails perfectly into my next question. When you think about it -- you've talked a little bit about the competitive landscape already. When you think about the compression space, I guess, everyone for the most part plays in their own sandbox. And really, I guess the only way to expand the footprint is to acquire horsepower of another outfit in a respective region.

So, with the turbulence this space is seeing, there's a chance some operations could be put up for sale. So, if that were to happen, I guess, how quick would USA be willing to explore entering a transaction? And is there a specific region you think would be more favorable than versus another maybe?

Rich, it's Matt. I think overall we look at stuff constantly. And even in the current commodity environment, stuff is -- people are talking and looking for alternatives.

When we look at it -- again, Eric mentioned that over the history USA has predominantly been an organic growth story. Well, you have to consider kind of our asset base. If we buy somebody who's in an area that we're not in -- it's not the same as buying a pipeline in that area, because that stuff can all move around.

And so, when we think about M&A, think about operators or other fleets, you want to make sure that the stuff you're buying is compatible with your current fleet -- new vintage, high horsepower stuff, good customer base. So, it's going to be more those sorts of considerations, I think, than necessarily a new area.

The two may coincide. You may find somebody who's got an unbelievable market position in a new area, and that may be something that's attractive.

But again, back to I think capital access, cost of capital. It's certainly been a little bit more difficult to get stuff done the last six, 12, 18 months. But I think that will -- we're in a cycle and that'll change. And I think just like in the past, people will -- there will be transactions to be done. I just think we're going to be very disciplined about who and what we go after.

That's excellent color. Thank you, Matt, and thank you, Eric, for the time. Guys, I appreciate it, and congrats again.

We have no further questions at this time,. I'd like to turn the call back to Eric Long for any closing remarks today.

Thank you, Operator. The entire USA Compression team thanks everybody on the call today for your continued support of our Company and for participating on our call.

We continue to believe that we have a differentiated and superior business model to those of our various peers, public and private alike. We continue to demonstrate our ability to maintain our margins and distributions due to the stability that our demand-driven focus on the larger horsepower infrastructure-oriented compression business offers in comparison to other sectors of the energy business.

While the next few quarters will no doubt be challenging for all of us in the space, we will work to continue delivering exemplary levels of compression services to our customers and focus on our balance sheet, our leverage, optimizing cash flow, and maintaining appropriate coverage.

We look forward to our second quarter update call sometime in early August. Have a great day.

This does conclude today's conference. Thank you for your participation. You may disconnect at any time.