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Good afternoon, ladies and gentlemen. Welcome to the High Arctic Energy Services 2022 Q4 Results Conference Call.
I would now like to turn the meeting over to High Arctic’s Chief Executive Officer, Mike Maguire. Please go ahead.
Thank you, Chris, and good morning, everyone, or good afternoon to those in Canada. I’m talking to you from Brisbane at the moment, and thank you for your patience waiting for us to begin as I experienced a few technical difficulties getting online.
Welcome to High Arctic’s fourth quarter conference call. Today, I’ll be providing an update on the press release we issued early this morning, March 28th. Following my remarks, I will hand the call over to our Chief Financial Officer, Lance Mierendorf, and Lance will be discussing our financial performance for the fourth quarter of 2022.
After our formal comments, we’ll open the call to answer any questions that you may have. Before we begin, I’d like to remind you that certain information presented today may include forward-looking statements. Such statements reflect High Arctic’s current expectations, estimates, projections and assumptions. These forward-looking statements are not guarantees of future performance and are subject to certain risks, which could cause actual performance and financial results to vary materially from those contemplated in the forward-looking statements. For additional information on these risks, please take a look at our management’s discussion and analysis and the 2022 Annual Information Form available on our website or on SEDAR. Look under the heading Risk Factors.
Well, following the divestments of our Canadian Production Services segment in the third quarter, we have focused on Papua New Guinea in this fourth quarter. PNG is a market where we have a dominant energy services position, a history of high profit margins and free cash flow generation. Papua New Guinea is now central to High Arctic’s long-term business strategy. And during the fourth quarter, we ramped up both, our deployed operational personnel and crews as we readied Rig 103 to commence operations and build key managerial and support positions within our PNG operations.
We took a deep dive into the large inventory of spare parts, equipment and consumables to ensure we have a solid understanding of our capacity to support our growing operations in PNG. We also progressed preparations for Rig 103 to commence drilling activity with the work scope that was expanded to include an upgrade of its top drive. And I’m pleased to confirm the upgraded rig is currently operating again, having returned to the well that was drilling was suspended on back at the beginning of the COVID travel restrictions in 2020. High Arctic anticipates Rig 103 will operate consistently through the term of the contract, which runs through to July 2025.
This recommencement of drilling operations follows the recent announcement in PNG that the total energies led Papua LNG project has commenced downstream front-end-engineering-and-design work or FEED. This follows certain upstream FEED work that commenced last year and continues to progress towards the final investment decision expected later this year. Indications suggest the Papua LNG project will be based on 4 electric-driven LNG liquefaction trains housed in the existing export facility in Port Moresby, the capital city of Papua New Guinea. This facility is operated by Papua LNG partner, ExxonMobil for the country’s other LNG projects.
TotalEnergies has recently outlined plans to bury almost 1 million tons per annum of carbon dioxide with the Papua LNG project and a major tree planting project to boot. We expect the sequestration of CO2 to require additional wells to be drilled on top of those plants for gas production.
Last week, Mr. Wapu Sonk, the Managing Director of the National Oil Company, Kumul Petroleum, was quoted stating that they are in early talks with potential partners to build their own LNG processing unit. Mr. Sonk said the proposed 1 million ton a year unit would be in addition to the new units to be built by the Papua LNG venture and would be fed from undeveloped gas that Kumul Petroleum have secured retention licenses over. These developments support management’s optimistic outlook on the gas development activities in PNG, which are expected to lead to increased demand for drilling and related services.
I’d like -- now like to pass the call over to Lance to discuss key financial highlights from the quarter in more detail.
Thank you, Mike, and good afternoon to those joining on the call today.
Our fourth quarter results are the first complete quarter without contribution from the Production Services segment, which was divested in July of 2022. On a consolidated basis, High Arctic generated revenues of $13 million and incurred a net loss of $9.1 million or $0.19 a share in Q4. Q4 oilfield operating margins were significantly impacted by inventory adjustments, which led to a loss -- operating loss of $2.4 million. While on a full year basis, the oilfield operating margin was $11.9 million or 15% of revenue.
During Q4, we recorded a net provision of $3.9 million stemming from an extensive evaluation and counting of inventory, materials and supplies located at various sites in Papua New Guinea. The adjustment included $4.5 million inventory write-down, offset by a $600,000 reversal of a provision for obsolescence. Not only did we examine and assess our own inventory, we conducted extensive counts of inventory that we manage on behalf of a main customer in Papua New Guinea. We find to utilize this -- some of this inventory, both from our stock and from our customers to own stock on the ongoing operations of Rig 103. In Q4, we recognized a liability of $3.3 million relating to customer inventory, which we were obliged to replenish, pursuant to contractual obligations. This liability forms part of the -- the total contingent liability of $8.3 million, which we reflected in the notes to our financial statements in the contingency section.
Following this evaluation, and again as Mike pointed out, we are confident that we have sufficient and appropriate material supplies on hand and at present to support our ongoing operations in Papua New Guinea.
The Company recorded negative $892,000 of adjusted EBITDA in the quarter and generated $5.4 million -- $5.7 million, sorry, of adjusted EBITDA for 2022, up from $4.9 million in 2021. In 2022, High Arctic experienced a $0.75 loss per share, of which 44% relates to noncash items of impairment, a reversal of deferred income tax, assets and inventory provision.
During the fourth quarter, High Arctic provided personnel, materials handling equipment and associated rental equipment, including a 100-man camp and a large quantity of Dura-Base mats in support of customers’ field operations with our 2 primary customers in Papua New Guinea. In addition, we increased drilling personnel deployed to prepare Rig 103 for the recommencement of development drilling activities.
These activities in our Drilling Services segment generated 10.1 in the quarter, and we surpassed C$30 million of drilling service equipment for the year. The drilling segment margins have been impacted by the previously discussed inventory adjustments and low-margin reimbursable cost contribution associated with the supply and installing the top drive on Rig 103.
When adjusted to back out the impact of the provision of inventory write-down, the Drilling Services segment margin increases from 4.4% to 15.4%, a figure that’s comparable to 15.6% experienced in 2021.
Our Ancillary Services segment spreads across both PNG and Canada and continues to be our highest operating margin generator. We achieved 44% operating margin during the quarter and 54% across 2022 on revenues of $2.9 million and $14.9 million, respectively. With increased activities in PNG and consistent demand for pressure control rentals and nitrogen services in Canada, we do anticipate this segment to continue to grow in revenue as we move to 2023.
The Company continues to be prudent with its capital management and maintained a strong balance sheet. During the quarter, capital expenditures were limited to under $100,000, and we spent $4.1 million on capital during the year. We expect modest capital spending in 2023, mostly focused on maintaining rental equipment and our drilling fleet.
With the cash proceeds from the sale of the Well Servicing business last July, the Company ended the year with $19.6 million cash and cash equivalents. Inclusive of the Precision receivable, our working capital ratio increased to 7.7 to 1 at the end of the year. This year and following year-end, we did flex with $20 million from the sale of the Well Servicing to Precision and we placed stock into their [ph] accounts earning between 4.5% and 5%.
High Arctic continues to pay monthly dividend of $0.005 per share. And in Q4 2022, we renewed our NCIB to repurchase shares throughout 2023. We continue to assess financial options in line with our strategic objectives moving forward. And the Company has a history of returning surplus cash to shareholders and we’ll continue to consider our capacity to distribute surplus funds while exploring opportunities to invest into strategic growth activities as they emerge.
With that, I’ll pass it back over to Mike.
Thank you, Lance.
High Arctic has taken transformative actions in 2022, which will allow the corporation to focus on the emerging opportunities to deploy drilling assets in Papua New Guinea, while maintaining exposure to the Canadian energy services market. High Arctic believes that the fundamentals for sustained high LNG demand, particularly in Asia, positions PNG for substantive liquefied natural gas export growth and the contemplated expansion projects are progressing.
While the restart and drilling activity has been slower than we expected, High Arctic is optimistic for future drilling contracts in the coming activity cycle associated with the major project advancements. High Arctic maintains active dialogue with the management of all active energy companies in PNG towards understanding their project time frames and plans for drilling activity and the potential for utilization of High Arctic’s drilling assets.
We’ve now realized the drilling rig deployment in the first half of 2023 and expect to continue to increase deployment of rentable assets and ancillary services through 2023. We expect that as the major projects move into execution, the demand for drilling has the potential to exceed our past activity peaks.
I will now turn the conference call over to the operator, who will open the line for questions.
[Operator Instructions] Our first question is from?
Josef Schachter. Mike and Lance, just kind of going at the macro level. How many -- how much Bcf will go through on 4 electric-driven trains? How much capacity with gas goes through right now on the current system? Just to get an idea of scale of the ramp-up. And then, if one of these companies decide they want to start drilling a little quicker, Lance mentioned that the CapEx for ‘23 might be less than ‘22. Could there be an announcement Q3, Q4, if there is a ramp up where your CapEx budget would go up quite a bit, and you want to more husband the cash for putting all the equipment to work and doing whatever upgrading you need to meet the clients’ requirements.
Yes. Thanks, Josef. I’ll start with the first part of the question on the throughput of the facility. I don’t have the figures to hands in Bcf, but the total annual numbers are top of mind. The current facility, I mean that’s 2, what we’d call, I guess, conventionally gas-driven trains put out -- currently put out 8.4 million tons per annum. The electric trains are to be smaller in scale. I understand that they’re expected to put through somewhere around 1 million tons per annum. So with 4 of those for the Papua LNG project expansion that gives them capacity of 4 million tons per annum. I would bear in mind that the nameplate capacity of the PNG LNG 2-train -- export facility is 6.4 million tons per annum. So it has operated substantively around 25% above capacity since it came on line. These electric trains, I’m not sure how much additional capacity they may have above that design target of 1 million tons per year but that’s the figure that was quoted by the Managing Director of Kumul Petroleum.
The second question relating to the capital expenditures. We have revised our budgets for 2023 with the slower start-up that we’ve seen and experienced to date and expectations that the customers are deferring drilling activities into 2024 and 2025. So, we don’t expect to have to incur substantive capital expenditures this year based on the expectation of only having the one rig, Rig 103 out of work, unless one of those other projects does start to come forward in the back half of the year from current expectations of 2024.
Where we do expect to spend some capital is in the growth of deployment of ancillary rentable equipment items such as the Dura-Base matting product and our fleet of material handling equipment has started to experience substantive upswings in requests for service. And we have projected to spend a modest amount of capital on -- in growing that fleet of equipment through 2023.
I can add one more on the overview. If they do FID, everything, are we looking at ‘27, ‘28, ‘29, ‘30 for when they’ll be on -- the train starting up? Just trying to get an idea of the time line that we’re looking at.
Yes. I haven’t seen a specific date mentioned by the project proponents but there is discussion around a lot of the quoted statements in the media, which indicates a 2027 online first gas from the new project.
The next question is from?
Would you be able to break down -- just a large difference, if you could break down the $8 million fund flow used in operations during the quarter and compare that to the adjusted EBITDA of negative about $1 million, so I can understand the cash impacts there?
Sure. I’ll let Lance answer that question.
Sorry. I’m going to -- that’s a decent digging on that one. What was the question again?
Sure. It’s there. I think you guys have for the quarter, about $8 million fund flow used in operations versus the adjusted EBITDA of about negative $1 million.
Yes. Okay. So, I’ll pull it up real quick here, maybe we can go on to the next question. I’ll pull it up real quick.
Sure. Would you guys be able to discuss any results at Team Snubbing or as it’s not consolidated into the Company?
Yes. I’ll have to let Lance answer that one as well. While he’s looking up those numbers, I can give more of a qualitative answer and that Team Snubbing has -- and I think I said this at the conference call in November that they had immediately upon aggregation of the 2 businesses expanded their service offerings in Canada to greater than what some of the two parts were coming together, and they’ve maintained that all the way through the first quarter. They’re also now contemplating and moving equipment up to Alaska as part of their international partnership, of which they have a 50% off. So the 50% partnership there in Team Snubbing international operation up in, I guess, it’s the USA, right, but Alaska and mobilizing equipment up there, which includes some of the snubbing packages that were acquired from High Arctic as well.
Sounds good. Maybe one other sort of bigger picture question. Just if High Arctic has only the drilling Rig 103 in regular consistent activity during the year, do you expect that that on its own, along with the ancillary rental equipment would allow the Company to be profitable for the year?
Yes. Our projection is profitable on a cash basis. So, if one knocked out depreciation expense, which is still quite a large number given that we’re still depreciating the drilling assets in PNG. We would expect to make cash profit but probably a modest loss -- financial loss.
And I guess while waiting, just you guys have mentioned that there’s still being consideration at the -- of what to do with the net sale proceeds. Earlier, I think there was an indication that there would be a consideration of potential distributions of the cash to shareholders about the time of the final payments, which I guess was earlier in January. Has there been further discussion among the Board about that?
Management has undertaken an extensive analysis of our forward needs and have explored several different scenarios for the use of those proceeds, none of which have matured to a point where we can say something specifically about at this point, but it is front of mind.
Okay, I guess we’ll keep listening for that.
Lance here. I think the reconciliation is that we didn’t have any activities from our operations in Canada, right?
Right.
And we did have much lower margins in PNG for reimbursement -- like reimbursement costs. We did a lot of spending on costs that we spend forward purchase on behalf of the customer and then acquire them and then -- acquire them, transfer and install them. There’s a lower margin percentage on that.
Got it. Is there also -- is the $4.5 million inventory adjustment, is there -- was there a related cash outflow on that or not at this time?
No. Absolutely not. No, that’s -- there’s -- like I said, there’s sufficient -- sorry, inventory on hand. We did not make any additional purchases at all. We don’t anticipate making any purchases of large quantities of inventory. It’s all on hand and in country. And some of the -- you see mentioned an obligation to replenish inventory. So, that’s where we just need -- we, of course, over time, certain types of supplies and equipment -- it changes over time depending on the technological advances of the rig and the design of the drilling programs that we do for our customers. So, certain equipment changes over time. And that’s where we have in our inventory items that meet that specification and we work with our customer to draw some of the inventory from theirs and from ours to fulfill our joint obligations, to support our drilling operations. So it’s -- this adjustment was really just to verify what we’ve done with these accounts, is just verify all of that inventory in hand and on hand and what can be usable in the future and what’s relevant and what we need to replenish from what we’ve combined used within our operations over the last number of years.
[Operator Instructions] You do have the next question. Please go ahead.
Hey. Just really quickly, like what other assets, what do we have in Canada at this point in time outside if you have an investment, you have a receivable. What else exists in Canada?
So, we have nitrogen pumping service line that consists of 5 active lower rate pumpers, on high rate pumper and a fleet of support equipment in both the transport and nitrogen. They provide services, mostly through the northwest of Alberta to an array of customers that include both service companies and oil operating companies. And we have a rentals business, which is centered around the provision of pressure control equipment, which includes things like flow out preventers, but also high-pressure ion valves and other pressure control equipment as well as the smorgasbord of other ancillary rentable items from generators and office trailers through to heating units, space heaters and oilfield handling equipment. It also has an array of customers that include both service companies, and oil and gas E&P companies.
And what...
I’m sorry?
Sorry. I’ll let you finish there first.
I was just going to say and then there’s 5 dormant snubbing units in Colorado that we have essentially decided to divest, and we’re looking for a buyer to take those units. You were going to ask another question I think about real estate, was it?
Yes. Because I know at year-end, there was still a mortgage, but I don’t know if that went with the Precision assets.
Yes. So, there were some owned and some leased properties that transferred across with the sale of our Well Servicing business to Precision Drilling. We retained owned properties at Whitecourt, which is now our Canadian headquarters where our rentals business is operated out from and a larger facility in Clermont just outside Grande Prairie. That facility has been leased on a long-term basis to an affiliate of Team Snubbing, and we basically become landlord there. Both of those properties have got a mortgage on them. They’ve an approximate value, I believe, Lance, at the moment around $3.7 million?
Yes, about $4.2 million right now, Mike. Yes. And it’s around 75% of the value of those properties.
Okay. Thank you. To hop back into Papua New Guinea, one of the questions Josef had was on expenditures, and you said it’s not significant for this year. But if and when the operations pick up and I’m going to pick ‘24, ‘25, is it a material amount of expenditure of capital outlays that you would have to incur in order to get the other rigs up? Because I remember they were -- they’re stacked, but one of them I don’t think have ever worked. So, it should be relatively in good shape? Or is there going to be a material -- and I’ll use material as $5 million to $10 million CapEx, in order to put those units to work?
Yes, there would be some money need to be spent to return equipment to work, but nothing near the band that you just outlined is material. We expect the cost to put any of the rigs that we have sitting idle and responsible for at the moment to work, we would expect the capital expenditures of sub $3 million depending upon which one it was.
Okay. Do you see any other competitors right now in PNG, or are you still really the only game in town for heli-portable?
We’re the only company that owns or operates any heli-portable drilling units in Papua Guinea, at the moment.
There are no further questions registered at this time. I would now like to turn the meeting back over to Mr. Maguire.
Thanks, Chris. I’d like to thank the participants who joined us today and the thoughtful questions that were put to us, and wish everybody a good day.
Thank you. The conference is now ended. Please disconnect your lines at this time, and thank you for your participation.