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Good afternoon. My name is Cheryl, and I will be your conference operator today. At this time, I would like to welcome everyone to the Ensign Energy's second quarter results. [Operator Instructions] Ms. Nicole Romanow, Investor Relations, you may begin your conference.
Thank you, Cheryl. Good afternoon, and welcome to Ensign's second quarter conference call and webcast. My name is Nicole Romanow, Investor Relations at Ensign. This afternoon, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's second quarter results, followed with a market update on what we see transpiring in the back half of the year. We'll then open the call for questions and have a final wrap up at the end of the call.With that, I'll pass it on to Bob.
Thanks, Nicole. Good afternoon, everyone. Today, we will be reviewing Ensign's second quarter results, as mentioned, followed by market update and a wrap up at the end of the call. Let's start with a few highlights of the quarter from our perspective.This quarter is the first quarter where you really start to see the impact of the Trinidad acquisition and its impact not only on the synergistic cost savings but also with margin expansion. Margin expansion, I'll point out against the headwinds of the market.Ensign's second quarter EBITDA essentially doubled year-over-year from $53 million to $100 million. Quickly following on the Trinidad acquisition, Ensign successfully established a solid capital structure into the future with the issuance of USD 700 million in senior notes.As a result of having a relatively young fleet of high-spec rigs across the key active regions around the world, Ensign's capital required to maintain and recertify the fleet is a very predictable figure. That figure for 2019 remains unchanged to just over $100 million.As mentioned on prior calls and driven by the market's demand for return on capital in the OFS space, Ensign established a unique philosophy that our clients need to cover capital upgrade costs. In this quarter, $6.7 million of the $31.9 million was upgrade CapEx, and that $6.7 million was fully funded by the clients. The remaining $25 million, of course, is the scheduled and planned maintenance CapEx for the quarter. This keeps us on track for an annualized CapEx of just over $100 million, net of CapEx funded by clients.Also happy to report that we also completed the beta testing of our first commercial hybrid ADR rig in this U.S. Rockies, more on that in our U.S. business summary.I'll turn it over to Mike Gray for a detailed summary of the second quarter. Mike?
Thanks, Bob. Usual disclaimer. Our discussion may include forward-looking statements based on current expectations and involve a number of business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to, political, economic and market conditions; crude oil and natural gas prices; foreign currency fluctuations; weather conditions, the company's defense of lawsuits and the ability of oil and natural gas companies to pay accounts receivable balances and raise capital, or other unforeseen conditions, which could impact the use of the services supplied by the company.Operating days overall were higher in the second quarter of 2019 with the Canadian operations experiencing a 59% increase, United States a 100% increase and the international operations showing a 16% decrease compared to the second quarter of 2018. For the 6 months of 2019, our operating days were higher as well, with the Canadian operations experiencing a 57% increase; United States operations a 114% increase and international operations showing a 9% decrease compared to the first 6 months of 2018. The increase can be attributed to the Trinidad acquisition.Adjusted EBITDA for the second quarter of 2019 was $100.4 million, 89% higher than adjusted EBITDA of $53.1 million in the second quarter of 2018. Adjusted EBITDA for the first 6 months of 2019 totaled $215.9 million, a $110.5 million higher than adjusted EBITDA of $105.4 million generated in the first 6 months of 2018. The 3 and 6 months of 2019 increase in adjusted EBITDA was a result of synergies obtained through the acquisition of Trinidad as well as globalization revenue from the Kuwait rigs in the joint venture.The company generated revenue of $377.7 million in the second quarter of 2019, a 44% increase compared to revenue of $263.1 million generated in the second quarter of the prior year. For the first 6 months of 2019, the company generated revenue of $823 million, a 58% increase compared to revenue of $521.5 million generated in the first 6 months of the prior year.Gross margins, which is revenue minus oilfield services expenses increased by 69% to $109.8 million or 29.1% of revenue for the second quarter of 2019 compared to gross margins of $64.8 million or 24.6% of revenue for the second quarter of 2018. Gross margins increased to $237.3 million or 28.8% of revenue for the 6 months ended June 30, 2019, compared to a gross margin of $127.9 million or 24.5% of revenue for the 6 months ended June 30, 2018. The increase in gross margins for the 3 and 6 months ended June 30, 2019, versus that of the corresponding periods in 2018 was primarily attributed to higher activity levels in the current period, effective cost control in operations and the realization of synergies from the Trinidad acquisition.Depreciation expense in the first 6 months of 2019 was $177.2 million, a decrease of 11% compared to $199 million in the first 6 months of 2018. The decrease is due to the policy change that took place in Q1 2019. General and administrative expense in the second quarter of 2019 was 36% higher than the second quarter of 2018. The increase in G&A was largely from the Trinidad acquisition. Total company debt, net of cash balances, decreased by $65.2 million or 4% in the second quarter of 2019 to $1.62 billion at June 30, 2019, from $1.69 billion at March 31, 2019.Net purchases of property and equipment for the second quarter of 2019 totaled $4 million, which includes the sale of the testing and wireline assets. Net purchases of property and equipment during the 6 months 2019 totaled $43.7 million, which is inclusive of the testing and wireline asset sale.During the first half of 2019, the company transferred 1 ADR drilling rig from Canada to The United States, deployed 1 service rig in The United States fleet, moved 5 underutilized drilling rigs into the reserve fleet and decommissioned 1 drilling rig and 7 service rigs in Canada. Net capital expenditures funded by the company, excluding the sale of the wireline and testing assets for the calendar year of 2019, remains at just over $100 million. The company will continue to focus on innovative strategy to address the technical demand of our customers.On that note, I'll turn the call back to Bob.
Thanks, Mike. So let's dive into each business unit around our world with an operational update, starting with our largest operating segment, The United States, which has 3 operating areas and contributes roughly 2/3 of the company's revenue: the southern business unit which operates in the Permian, Eagle Ford and Haynesville; the Rockies business unit which includes the Bakken, Jonah and DJ areas generally; and the California business unit which covers the Bakersfield and the LA basins.With the Trinidad acquisition, we have one of the newest and largest fleets in the U.S. We operate 134 rigs in the Continental U.S. and generally run an active utilization of approximately 65%. We also run a very active and growing well servicing division, which operates 47 wells service rigs, with the utilization of roughly 70%. Ensign, in spite of the market headwinds that has affected active rig counts for most of our competitors year-over-year, has held on and expanded its market share in the U.S. Ensign had about 84 rigs running in the U.S. a year ago and today has about same number running.No question that operators are sticking to budgeted CapEx with commitments with conviction. We're finding that we are generally able to recontract the rigs in the same week, and that for every operator, we have that maybe compressing their rig fleet under contract. We have clients who wish to discuss adding more of the Ensign ADR rigs to the stable. Rigs have arguably dropped off $500 to $1,000 a day over the last month. To offset that, Ensign has been expanding its Ensign Edge technology platform, which goes out for about $900 a day.Also to capture more of the value on our high-spec rigs, which bring to the table when coupled with their AP and advanced performance management offering, we continue to have more discussions with the clients around performance-based contracts with the base day rates established along with performance metrics that can improve our net implied day rate and the associated margins by as much as 50%.These performance-based contracts also allow us to expand our directional drilling footprint, and we and our Edge technology platform, along with our Criterion DGS that we acquired through the Trinidad acquisition. With performance-based contracts, Ensign becomes a service congregator and can really start to push obvious efficiencies. This is an area we feel we'll continue to grow as operators move past the 3 bids and a buy mentality and look at total well construction cost efficiency.Also in the quarter, we finalized beta testing on our first hybrid ADR drilling rig in the Rockies. The rig utilizes what is called the BES, battery energy storage system, which solves the age-old problem of natural gas power lag. For years, natural gas power grids have been challenged with the power lag. Similar to turbo lag one sees on cars, with the BES system, the rig pulls out by using the electric full-on torque provided by the BES and then transitions into the natural gas power generators seamlessly. The result is an 80% reduction in NOx emissions and a 15% to 25% reduction in CO2 emissions. All this and a roughly 20% reduction in fuel cost.Moving over to our Canadian business unit, which contributed roughly 15% of our total revenue in the quarter. We operate 118 drill rigs and 55 well service rigs, along with the directional drilling division, a MPD division and a rental group called Chandel Rentals.Canada, as you know, has macro geopolitical issues that created a curtailment scenario, which undoubtedly was a necessary solution, but has created a huge activity headwinds, which we feel will subside as operators work through their cash flows and show disciplined reinvestment through the drill bit.We sense that CapEx spending will continue to be disciplined through the rest of 2019. With the takeaway capacity looking to improve via the TMX second line, et cetera, we should see 2020 to be a year where we expect a more robust return to activity.Our Canadian MPD division looks to expand its business later in the year with the deployment of 2 MPD units onto a couple of Canadian Ensign rigs, where the controls of the MPD units tied directly into our Edge Controls systems. This eliminates 2 person on location and provides more seamless UB control with Edge automation and higher margins.Moving to our international business unit, where we operate 50 drilling rigs in 8 different countries and generate roughly 20% of our revenue. We have about 50% of our international fleet working today. I'm happy to report that we now have both our 3,400-horsepower AC joint venture rigs on the payroll in Kuwait. The process of constructing and modifying the rigs has been over a year and the team has performed amazing through the process.In Australia, we had a great quarter with 3 retrofitted rigs operated -- funded upgrades, I'll point out, spudding and starting their long-term contracts. We have 2 additional rigs that have been going through upgrades, and which we fully expect to start their contracts in the third quarter.These are also operated-funded upgrades. These -- or this will put our Australia utilization up close to 70% in the back half of the year. In Bahrain, we have 1 rig operating, which is a JV rig. And we'll have the second rig starting an Ensign-owned rig, its third -- I'm sorry, its 3-year long-term contract in September. Oman continues to be a benefactor of our ADR technology, with our major client there signing up 3 of our ADR 350s for another 3-year term.In Argentina, we continue to have high demand for our 2,000-horsepower rigs in the Neuquén area. And as you're well aware, we are also operating 2 rigs in Venezuela for a major who has state department exemptions that allow them to continue to operate in the region. We are de-risked in the contract. We get paid in U.S. dollars in offshore every 30 days.On the Edge Controls technology front, we now have our Edge Controls installed on 45 rigs and have already started integrating after the Trinidad rigs in the Permian. We expect to roll additional installations through the fleet, building up to 2 a month later in the year.Recall, we purposely built our Edge technology platform with the middleware we call the Edge gateway to enable our Edge Controls platform to be easily installed on any type of rig for less than $100,000. We can also do this while the rig is operating, so the install is very efficient.We are beta testing at one of our U.S. rigs a new Ensign Edge rig automation system that will essentially solve the last piece of the artificial intelligence puzzle between live directional drilling guidance, Ensign's Criterion DGS and machine control where the control of these making decisions powered by machine learning.This will eventually drive full automation and drill the most efficient wellbore from a cost and repeatability perspective. This is easier said than done, and I'll point out that we are in the beta testing phase on this.So with that, I'll turn it back to the operator for questions.
[Operator Instructions] And our first question comes from Jon Morrison, CIBC Capital Markets.
You talk about moving the 1 rig from Canada to the U.S. in the quarter. Can you give any more color on what specifically drove the decision to move the rig? Was it just a function of duration of the contract? And was part of the move cost covered by the clients in this case?
Yes. The contract -- basically, we were able to double the EBITDA and into a 2-year fixed term contract with a full carry on the move from Canada to the U.S.
Okay. Is there any reason to believe that, that was one-off or you could ultimately continue to move more rigs, especially if you talk about the next 6 months being challenging just from an activity perspective?
Yes. I think what's happened is the -- it was a 1,500-horsepower AC rig. And Jon, the 1,500-horsepower AC rig in Canada has tightened right up. That was probably the last one to exit and become a catalyst for improved day rates in the rig category in Canada. We have no intention of sending anymore out of Canada at this point in time. We're able to raise our rates $4,000 to $5,000 a day on that rig category in Canada on contract turnovers. So there is a little method to our madness as you can see.
Perfect. That's helpful. When you take into account all the puts and takes in around the momentum you're seeing in Australia and some of the recent contract wins in the Middle East against some of the headwinds you see in Venezuela from a trailing perspective. Would you expect margins to be meaningfully higher in the next 12 months versus the past 12 months, specific to international?
Yes. I would say so for sure. I think we're growing our operational base, of course. The last 6 months has been transitional for Australia. There's been a 5 or 6 rigs that have been upgraded and moved on to term contracts that were up probably 25% on an EBITDA basis. So you'll see in the back half of this year into the future a full year continuance uptick.You will also see in the Middle East the effects of the 2 Kuwait rigs running plus in September the Bahrain rig will start its first year of a 3-year plus 2-year extension contract, where the operator funded all the CapEx as well. So we have been raising rigs international. We have been in the U.S., as you know, the Permian has had a little bit of pressure. Having said that, we've been able to recontract our rigs and basically hang on to our margin. We're working harder to hang on to the margin through other mechanisms, such as Edge Controls and that. And then Canada, outside of the 1,500-horsepower rigs, the typical market has been very, very tough.
And Bob, when you're talking about the rates of change when you're recontracting rigs, would that be fair to say that you're talking about changes in sport, not necessarily referencing the previous contract on that rig to when it is now because obviously that can fix 24 months ago?
Yes. It would be a net over what is currently contracted at. Keep in mind, international, we go through a much lower contract beta. They're usually contracted. I'm short-term, international is 1 year. And typically, we run 3 to 5 years on our international contracts. So the beta is usually -- when we talk about the change, it's a change from its current contract. We don't get the same spot market comparative that you would be used to in North America.
Yes. Sorry, I was meaning more just specific to the North American comments you've kid economy there?
Yes. I would say that. Because contracts turn over, and you probably heard us references in prior calls that contracts were returning over on a year-over-year basis up, I would say, that, that has certainly stalled and is probably all $500 to $1,000 a day off of what you would call spot.
Okay. Just in terms of Australia, are you expecting much or seeing much cost inflation at this point? And is there any chance that you're going to need to look at adding incremental assets into that region over the coming period? Are kind of all the upgrades that you've mentioned should kind of meet customer demand at this point?
Yes. There's kind of a finite customer base there, Jon, and we own 1/3 of the rigs in Australia. And it's a relatively new fleet. We've got, I think, 21 rigs in Australia. We'll probably get up to about 15 rigs in the back half. So we have some more capacity if there's a little more demand. We see it reasonably predictable as far as, kind of long-term contracts go. You do get the occasional group in Australia that will raise some money and go drill 2 or 3 wells. So we got excess capacity to handle that as well. On your question about cost inflation, of course, [ paper ] is covered in our contracts, and there is a view that kind of governance the labor group on the rigs. So that's fairly stable. And is, of course, covered in the contract for escalation.
Perfect. Within Argentina, you talked about the broader outlook continuing to look positive. But if you think about specifically the very near term, are you seeing anything in terms of a pause in development plans because of the upcoming elections? Or most of the customers are kind of looking through that at this point?
They seem to be looking through that. In discussion anyway, Jon, I think, in Argentina if you're working in Argentina for some period of time, you get used to the geopolitical rhetoric that exist. The facts are that they are getting a $5 for the gas, and it is an area where they know how to drill a well and they're getting good wells.
Perfect. Maybe just the last one for me. Mike, is there anything you see in terms of the fleet quality on the Trinidad rigs that could lead you to believe that the forward maintenance spending requirements on that asset, this could be higher than your original thought or it's kind of all shaking out the way that you would have thought absent obviously activity levels throwing around the maintenance spend number?
No, it's all taken out sort of as we thought. So no surprises by any means.
Our next question comes from Ian Gillies from GMP.
With respect to the $50 million of sales proceeds you mentioned in the release, I mean are you able to write some detail around how you end with that number? Is it assessed values? Or is it comparable transactions in similar markets?
It's a bit of both. So currently we have the Trinidad manufacturing facility listed in Nisku for $20 million. We've also then consolidated into Trinidad office up in Nisku. So we have our campus that is being prepared to be listed as well, which will go for a larger chunk so when you add them up, from North America, which is really from North America, you get to about $50 million with that Trinidad manufacturing building in our campus being a large portion of that amount.
Okay.
There is for those, Ian, as Mike pointed out realtors' opinion to give us some sense of what valuations are.
And I mean if we move to the dividend, I mean can you maybe provide an -- bit of an update about your conversations with the Board? And with respect to payout ratios where the yield is, dilution impact, et cetera, and why you're maintaining the dividend given the yield today?
Yes. Well, of course, the discussions with the Board -- or the discussions with the Board, and we discuss this every quarter. When you think of, let's suggest $450 million of EBITDA payout ratio, cash payout ratio is about 10% on that basis. It certainly is how we discuss the item. I would say that in terms of the current share price today becomes a more interesting conversation for sure, Ian. But the Board will always perform the right function and do the right thing at the end of the day. But right now the conversation is more about -- is it impacting our ability to de-lever? Is it impacting our ability to do other things? And at this point in time, we feel it's not.
Okay. That's very helpful. And then last one, I mean on the international side. With the uptick in rigs under contract, relative to last quarter, same period last year, I mean can you talk a little bit about how you think that translates into an active rig count just given I mean the perceived view that efficiencies probably aren't quite as high in the international arena. So how many active rigs you think you may be running in relation to what's contracted in future quarters?
Yes. I think that -- of course, we can see a little further into the fog with the international contract group, which doesn't change as quickly as it does in North America. I think we'll probably be running in that 25 to 30 range. I see some -- we've got great upside year-over-year in Australia, which we've talked to and you all are aware of. In the MENA region, we'll have both of our rigs running in September. Our 2 Kuwait rigs are fully contracted and running. We've got little bit of upside in the Oman region. We've had some ongoing talks in Oman on our Edge Controls technology. And recall that we broke into Oman with our ADR technology and cut well times in half. And we've got a good, strong support there to perform similar types of things with other the rigs. And I don't think you're going to see anything happening more in Venezuela obviously, and Mexico is pretty quiet. So that kind of circles the world. So yes, it's going to be pretty much the same as far as number of rigs running. I think you're going to start to see the large impact of the joint venture rigs in Kuwait. And the Australian rigs 5 more will be accompanying EBITDA year-over-year starting here in about 1.5 months on an annualized basis. All 5 of them will be hitting the books.
Okay. Last one for me. I mean with some of the customer-funded CapEx, I mean obviously it's good step because you don't have to deploy the capital. But can you maybe talk a little bit about what you end up giving up on the back end because it is customer-funded CapEx? Is there any classes around you not be able to increase day rates or anything along those lines or...
No, we're covered with escalation. There -- of course, usually, in areas where we don't have as much competition. You would have one heck of a time getting that push down in Canada or even parts of the U.S. to the extent we have international. We have been quite successful in the last 2 years pushing the third pump and the fourth generator on to the operator, and getting heat -- getting some concession with a reduced rate increase through that time. I think that conversation has disappeared a little bit now. But we've kind of settled into -- operators they've got the equipment that they want to drill the wells they want. There's also a big debate on what is the magical length of horizontal wellbore. And we've got just there a week and a half ago, and now as a conversation in Midland was 2 miles maybe a more appropriate way and there's a lot of parent-child conversation going on to try and understand that.So yes, I think to answer your question, generally in certain areas of the world, you can push it -- we don't give up anything on the day rate. For instance, in Australia, we raised our day rates $3,000 to $4,000 a day and got the operator to put it up. So it really depends on the market.
[Operator Instructions] And I don't show any further questions in the queue at this time. I'll turn the call back over to Mr. Bob Geddes for closing remarks.
Thanks, Cheryl. Wrap-up comments. While the synergistic and market benefits of the Trinidad acquisition are obvious, Ensign continues to stay laser-focused on delivering the transaction as quickly as possible, while maintaining and operating as high-spec global fleet at the best-in-class levels for our clients. This ensures high utilization now and into the future for the full 20-year useful life of the rig. The issuance of the USD 700 million senior note also provides a stable capital structure into the future. We continue to recontract rig fleet on a weekly basis on how the fleet booked out as far as 5 years now with about $1.6 billion of revenue for the contracted.Thank you for attending. We look forward to reporting to you in 3 months' time.
Thank you very much, ladies and gentlemen. This concludes our conference for today. You may now disconnect.