Helmerich and Payne Inc (HP) 2022 Q4 法說會逐字稿

Good day, everyone, and welcome to today's Helmerich & Payne Fiscal Fourth Quarter Earnings Call. (Operator Instructions) And it is now my pleasure to turn today's call over to Vice President of Investor Relations, Dave Wilson. Please go ahead.

Thank you, Ashley, and welcome, everyone, to Helmerich & Payne conference call and webcast for the fourth quarter and fiscal year ended 2022. With us today are John Lindsay, President and CEO; and Mark Smith, Senior Vice President and CFO. John and Mark will be sharing some comments with us, after which we'll open the call for questions.

Before we begin our prepared remarks, I'll remind everyone that this call will include forward-looking statements as defined under the securities laws. Such statements are based on current information and management's expectations as of this date and are not guarantees of future performance.

Forward-looking statements involve certain risks, uncertainties and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, our quarterly reports on Form 10-Q and our other SEC filings. You should not place undue reliance on forward-looking statements, and we undertake no obligation to publicly update these forward-looking statements. We will also be making reference to certain non-GAAP financial measures such as segment direct margin and other operating statistics. You'll find the GAAP reconciliation comments and calculations in yesterday's press release.

With that said, I'll turn the call over to John Lindsay.

Thank you, Dave, and good morning, everyone. I appreciate you joining us on our 2022 fiscal year-end call. We're pleased with our fourth quarter results and are optimistic about fiscal '23. My primary themes will focus on 3 areas this morning: North America Solutions pricing and margin cycle dynamics, H&P's international opportunities and our technology and sustainability investments. Our financial results improved substantially quarter-over-quarter as pricing increases and better contract economics took hold across more of our FlexRig Fleet.

You may recall from our previous earnings calls this year, we made the point that our rig pricing needed to improve to a level that provides at least a 50% gross margin in order to achieve returns above our cost of capital. I'm encouraged to report that our leading-edge pricing levels are now delivering margins in line with that goal. These are results not seen since the 2012 2014 out cycle.

Strong demand from customers, coupled with rollovers of term contracts should help drive average pricing higher across our active fleet, and we believe there is significant momentum heading into fiscal 2023. We plan to maintain a posture of fiscal discipline in our North America Solutions segment and continue to move our average rig margins toward leading-edge pricing and margins.

As such, we expect our financial results for the first fiscal quarter of '23 to follow the improving trend of the past 2 fiscal quarters. We are also seeing continued demand for our technology solutions. These solutions have and are anticipated to continue to add significant value for our customers. Many of our technology products and automation solutions are in high demand and are quickly becoming integral parts of the bid process, daily operational workflows and performance-based contracts. These solutions are contributing to H&P becoming the leading drilling solutions provider to many of our customers.

Our technology team is creating an exciting future where digital technology will be the key determinant that drives customer value by enabling safer, more efficient and reliable operations. In short, our people are actively caring culture, our rigs, technology and commercial models will continue to differentiate H&P's drilling solutions.

Let me now turn to some observations on pricing and margins in our asset-intensive business. A key metric to be mindful of here is how much of our customer demand can be satisfied by contractual churn rather than by introducing additional supply into the market. We've talked about churn on previous calls. In this instance, we define churn as the situation where a rig is released from one customer and then recontracted to another customer within an economically reasonable amount of time, enabling the rig to maintain a high level of activity.

During the past 2 quarters, the demand for FlexRigs has primarily been satisfied with readily available hot rigs. This allows us to postpone the investment of bringing a rig out of STACK and thus, exercise capital discipline. Here's an example. In our fourth fiscal quarter, only 1 rig was reactivated out of STACK in the quarter. That same quarter, however, we experienced a churn of 14 rigs. And in the third fiscal quarter, our churn was 18 rigs with 3 rigs reactivated. The takeaway is that the majority of customer demand in the past couple of quarters has been satisfied by rig churn, not rig reactivations. The reasons for higher or lower churn in the market have typically revolved around acquisitions, efficiency gains, acreage, budgets and supply chain delays.

We are seeing churn from both large and small customers, and we suspect this is happening across the market. Currently, while much of the rig demand is being satisfied through churn, there appears to be enough incremental demand growth to reactivate some rigs out of stack as we move into 2023.

We mentioned in our October press release announcing our supplemental shareholder return plan and fiscal 2023 CapEx budget that we would reactivate up to 16 rigs. This will allow us to attain a maximum of 192 active FlexRigs for fiscal '23 sometime during the second fiscal quarter. Regarding these planned reactivations – we're requiring term contracts of at least 2 years. As of today, roughly 2/3 are already committed, but the majority of those rigs going to large publicly traded E&Ps.

As in prior years, we expect most of these 2023 rig adds to begin working towards the front half of our fiscal year. Having said this, we also still anticipate contractual churn throughout the year similar to what we experienced in 2022, possibly averaging around 15 rigs per quarter.

Understanding these pricing dynamics, holding the line on capital discipline and not chasing market share is something we believe is crucial to creating a healthy and sustainable company over the longer term. This discipline extends to not only exercising prudence in fiscal restraint, but also careful consideration to putting capital to work in order to take advantage of longer-term growth opportunities. Having this mindset is enabling improved returns for our stakeholders, including investors who are returning to invest in the energy space.

Moving to our International Solutions segment. The company plans to deploy capital and preparation for more substantial growth in the future. We are seeing opportunities to bid in areas of existing operations as well as in countries that would be new to H&P. Most of the opportunities are where unconventional drilling is in its very early stages, such as in the Middle East.

The other opportunity here is the scarcity of digital solutions being applied in many key energy-producing regions around the globe. We believe our proven drilling solutions and technologies can provide significant value to national oil companies by just starting the unconventional learning curve. As we look to the future, we believe our international business is an important avenue of growth and serves as a potential outlet for some of our currently idle super-spec rigs in the U.S.

International growth also adds diversification to the company's revenue streams over the long term, and this current allocation of investment capital plays a pivotal role in the execution of our strategy. Shifting to the energy transition. We continue to further our strategy of deploying capital and expertise to companies playing an active role in the transition. As an example, our investments in geothermal are helping to develop an alternative low-carbon 24/7 power source.

We are providing FlexRigs and our digital technology solutions to enable enhanced geothermal systems and closed loop drilling concepts. Notably, we have made encouraging progress in field trials with 2 of our geothermal investees, Turbo and Fervo. Regarding Fervo, this past September, we completed drilling their enhanced geothermal system pilot project in Nevada, which involved the first 2 horizontal geothermal wells ever drilled in the U.S. And we're currently drilling Fervo's closed-loop pilot project in New Mexico.

Once complete, we expect this closed loop project to be the deepest and hottest directional geothermal well in history. Our strategic alliances with Fervo and Fervo and all of our investees has put us firmly on the path toward the advent of next-generation geothermal as H&P takes the lead in unconventional geothermal drilling. We are hopeful that these pilot projects lead to scalable, low-carbon geothermal developments utilizing FlexRig solutions.

Our second sustainability report will be published soon, and we will continue to provide the transparency that is important to our stakeholders. Our team is working hard to continue to raise the bar as a responsible leader in the energy services sector. In summary, we enter fiscal 2023 with momentum and increased confidence that our initiatives in our North America Solutions segment have gained traction and are delivering positive financial results.

We are also excited about the longer-term prospects and opportunities before us, particularly in our International Solutions segment. Finally, we believe we've achieved a balanced and responsive capital return methodology with our supplemental shareholder return plan. These actions align with the company's long history of financial stewardship by increasing the company's financial returns through long-term investment in the business and increasing cash returns to shareholders through the augmentation of our long-standing dividend commitment, where over the past 10 years, we have returned $2.4 billion in dividends.

In closing, during my 35-year career, I have never witnessed a higher level of alignment and communication with our customers, resulting in greater transparency and value delivery. As a service and solutions company, the successes H&P has achieved and plans to achieve would not be possible without our devoted, customer-focused and hard-working employee base, which I'm proud to say continues to set the standard for our industry.

And now I'll turn the conference call over to Mark.

Thanks, John. Today, I will review our fiscal fourth quarter and full year 2022 operating results, provide guidance for the first quarter and full fiscal year 2023 as appropriate and comment on our financial position. Let me start with highlights for the recently completed fourth quarter and fiscal year ended September 30, 2022.

The company generated quarterly revenues of $631 million versus $550 million in the previous quarter. The increase in revenue relates to continued price increases in the quarter for the North America Solutions fleet. Correspondingly, total direct operating costs incurred were $412 million for the fourth quarter versus $377 million for the previous quarter.

The sequential increase was driven by some structural inflation, but to a greater extent, maintenance and supply expense volatility that we typically see in North America solutions quarter-to-quarter, which ended up being on the higher end of the range this quarter.

General and administrative expenses totaled $47 million for the fourth quarter and $182 million for fiscal '22, which is in line with our expectations. In other income expense was a loss of approximately $9 million, which was primarily driven by a lump sum distribution for participants exiting our pension plan.

Our Q4 effective income tax rate was approximately 38%, which is higher than the statutory rate of 21% primarily because of foreign income taxes and permanent book-to-tax differences. As we crossed the line to become profitable towards the end of the fiscal year, we accrued additional U.S. cash taxes in fiscal 2022, of which approximately $45 million remains that we plan to pay with the extended filing of our tax return in January of 2023.

To summarize fourth quarter's results, H&P earned a profit of $0.42 per diluted share versus $0.16 in the previous quarter. Earnings per share were negatively impacted by a net $0.03 loss per share of select items, which was primarily made up of the aforementioned pension denim. Absence like items, adjusted diluted earnings per share was $0.45 in the fourth fiscal quarter compared with an adjusted $0.27 during the third fiscal quarter.

Capital expenditures for fiscal '22 totaled $251 million, which was within the range we established in November of 2021. For John's previous comments on market churn, we limited our rig reactivations mid-fiscal year in keeping with our strategy of capital discipline.

H&P generated $234 million in operating cash flow during fiscal 2022. As we discussed last quarter, our cash flow generation fully funded CapEx in our base dividend in Q3. And this quarter, we were able to do the same and even added some cash to the balance sheet as well. We will discuss accretive FY 2023 cash generation later in these remarks.

Turning to our 3 segments, beginning with the North America Solutions segment. We averaged 176 contracted rigs during the fourth quarter, up from an average of 174 rigs in fiscal Q3. We exited the fourth fiscal quarter with 176 contracted rigs as expected. Revenues were sequentially higher by $66 million due to pricing increases for our rigs in the spot market and continued repricing of term rollovers Segment, the direct margin was $204 million, just below the top end of our July guidance and sequentially higher than the third fiscal quarter by $36 million.

In addition, reactivation costs of $7.5 million were incurred during Q4 compared to $6.5 million in the prior quarter. The Q4 reactivation costs were primarily related to the rigs being prepared for deployment in the first few months of fiscal 2023. Total segment per day expenses, excluding recommissioning costs and excluding reimbursables, increased 16,453 in the fourth quarter from $15,490 per day in the third quarter. This was above our expectation due primarily to normal maintenance and supplies expense volatility as well as inflation that I mentioned previously.

Looking ahead to the first quarter of fiscal 2020 for North America Solutions. As of today's call, we have 180 rigs contracted, and we expect to end our first fiscal quarter with between 181 and 186 working rigs with expectations for a few additional adds in early January and with line of sight for up to 192 rigs by the end of fiscal Q2. Our current revenue backlog from our North America Solutions fleet is roughly $864 million for Ragener-term contract.

As of today, approximately 2/3 of the U.S. active fleet is on a term contract. Our increase in term value of approximately $235 million from June 30 to September 30 is due to: one, the reactivations in the first 2023 fiscal quarter requiring term contracts and 2 term extensions as well as some performance contracts for strategic customers. However, from now through March 31, we have about 65 rigs rolling off of term contracts with almost half rolling off on March 31.

As a result of these more legacy type term rigs rolling off, a tailwind is created for the average pricing level of rigs remaining under term contracts. Accordingly, in an oversimplified example, if all of these rigs roll to the spot market, we would expect the average pricing of our remaining term rigs to benefit roughly 1,500 per day over each of the next couple of quarters as lower priced term rigs were simply removed from the average. For reference, we expect the average revenue per day for our term rigs in the first fiscal quarter to be about $30,000 per day.

We still expect the percentage of U.S. fleet on term to be between 50% and 60% by the end of fiscal 2023. In the North America Solutions segment, we expect drug margins in fiscal Q1 to range between $250 million to $270 million, inclusive of the effect of about $8.5 million in reactivation costs. As of the recent start of fiscal year 2023, we increased field labor related rates to respond to market conditions and assist and talent retention and attraction.

As a reminder, our contracts are structured to pass through such labor-related cost increases over a 5% threshold. Therefore, significant labor increases are largely margin neutral at the time of adoption due to contractual protection. Also, approximately 70% to 75% of our daily costs are labor-related, and these recent increases are approximately $650 per day.

Our direct margin guidance is inclusive of our expectations for labor and materials inflation in the first fiscal quarter. Regarding our International Solutions segment. As expected, International Solutions business activity increased by 3 rigs to exit the quarter at 12 rigs having added 2 in Argentina and late in the quarter, one in Colombia.

As we look toward the first quarter of fiscal '23 for international, we expect to add another rig in Argentina and benefit from a full quarter of the recently added rig in Colombia. In our October press release, we mentioned upgrading 5 Argentina rigs to super-spec. These upgrades are performed in Argentina using local currency and are intended to meet ongoing customer demand for unconventional drilling.

We will have 9 of 12 FlexRig 3s working by December 31, we planning to upgrade the 5 that are not respect by the end of this fiscal year. We also expect to continue to incur more expenses as we further develop our Middle East hub inclusive preparation to export super-spec FlexRigs that will be targeted at regional unconventional drilling operations.

Aside from any foreign exchange impacts, we expect to have between $7 million to $10 million direct to margin contribution in the first quarter. While it will not contribute to activity until the fourth fiscal quarter of 2023, you may have read reports of our recent investment in rig contract with Tamboran Resources in Australia. Australia was on our long-term planning horizon for opportunities around burgeoning unconventional plays globally and we look forward to adding value by bringing our unconventional expertise and experience to this long-term project.

Our customer has key acreage in an emerging unconventional gas play in the Beetaloo Basin, and there are no current super-spec rigs in Australia that are suitable for such drilling. H&P's first rig in Australia is being scheduled to ship during the first half of the year. And if our customer is successful with their delineation work, we are hopeful that this will be a new region for international growth.

Turning to our Offshore Gulf of Mexico segment. We have 4 of our 7 offshore rig platform rigs contracted. Offshore generated direct margin of $9 million during the quarter, which was within our guided range. As we look toward the first quarter of fiscal '23 for the offshore segment, we expect that it will generate between $8 million to $10 million of direct margin.

Now let me look forward to the first fiscal quarter and full fiscal year '23 for certain consolidated and corporate items. As we increase our rig count, capital expenditures for the full fiscal 2020 year are expected to range between $425 million to $475 million. This capital outlay is comprised of 3 domestic buckets plus international and corporate spend.

As discussed on the July call, our North America segment CapEx has 3 buckets: maintenance, reactivation and conversion. Our bucket of maintenance CapEx cost is anticipated to push above the high end of our historical range of $750,000 to $1 million per active rig. The fiscal 2023 range is expected to be between $1.1 million and $1.3 million per active rig.

As mentioned in our October press release, the reasons for this are twofold. One is due to the reduced spending during the pandemic years when the company judiciously preserve capital spending by utilizing component equipment from idle rigs. Now we are making up for those capital spending deferments. The second reason is the current inflationary environment and supply chain challenges.

The second bucket for our North America segment is new for 2023 and includes rig-specific reactivation CapEx that is required for the planned redeployment of up to 16 rigs that have been stacked for some time. Much of the spend will be incurred to overhaul componentry that we optimally utilize during the protracted downturn, such discrete reactivation CapEx is anticipated to range from $1 million to $4 million for each of the 16 rig reactivations planned in the first half of fiscal '23, depending on the unique rigs particular componentry involved.

The final bucket for NAS is the conversion bucket, which relates to the continuation of our walking rate conversion program. We plan to convert 1 rig a month for the first 6 months of fiscal 2023 for reactivation in the U.S. market. As a reminder, our skidding to walking conversions are approximately $7 million per rig. The International segment also has 3 areas of spend concentration.

First, we are converting 6 stacked rigs in the U.S. from skinning walking in the second half of the fiscal year and also incurring recommissioning CapEx for those 6 conversions, which will be exported. Second, as mentioned earlier, we are upgrading 5 total rigs in Argentina to super spec. And third, maintenance CapEx for the international and offshore segments are collectively expected to be $1 million to $2 million per active rig.

Finally, corporate capital investments are expected to be about 10% of our fiscal 2023 CapEx. 2/3 of this is information technology related, including hardware lifecycle replacements, enhanced data capabilities and further improvements to our infrastructure communications and cybersecurity. Depreciation for fiscal 2023 is expected to be approximately $400 million.

A few overarching comments on capital expenditures are in order. First, CapEx is up year-over-year as we are investing to maintain our U.S. fleet with modest growth this year as well as investing in international growth for future year margin generation as well as geographic margin diversity.

It is important to note that after our planned 16 U.S. rig reactivations and our planned 6 international rig exports, we will have 32 remaining stacked super-spec flex rigs located in the U.S. for future growth domestically or internationally in upcoming years. Second, if you exclude the pandemic years of 2020 and 2021, capital intensity, which we measure as CapEx as a percentage of revenue should be among the lowest it has been in the last 10 years in fiscal 2023. This reduced capital intensity results in return and cash flow generation, which I will comment on more in a few minutes.

Finally, like fiscal 2022, we are committed to our CapEx guidance for fiscal 2023, barring any unexpected investment opportunities in international markets. Our general and administrative expenses for the full fiscal '23 year are expected to be approximately $195 million, which is up from the year recently completed, which had an average of 163 rigs working. While this annual G&A spend is just under the $50 million per quarter run rate we had going into the pandemic when we had approximately 195 rigs working.

We are expecting to operate about the same number of rigs in an inflationary environment, and at the same time, are building capabilities to support future international growth. In essence, we are doing a bit more with a little less for support costs. Specifically, we expect about $50 million of expense in Q1 with the remainder spread proportionately over the final 3 quarters.

Our investment in research and development remains largely focused on solutions important to our customers, such as drilling automation, lowball quality and power management. We anticipate R&D expenditures to be approximately $28 million in fiscal 2023. As a result of our return to profitability, we are once again becoming a U.S. quarterly estimated taxpayer. We are expecting an effective income tax rate range of 23% to 28% with the variance above U.S. statutory rate of 21%, driven by state and foreign taxes.

Based upon estimated fiscal 2023 operating results and CapEx, we are projecting a consolidated cash tax range of $190 million to $240 million, of which $45 million relates to fiscal '22 taxes to be paid in fiscal '23, resulting in a cash tax range of the $145 million to $195 million related to fiscal '23 activity. Of note, we currently estimate that the impact of our deferred tax liability roll-off for fiscal '23 is less than $10 million. It should be noted these ranges do not include approximately $28 million of federal tax receivables on September 30, 2022, of which about $25 million were subsequently collected in October after the fiscal year-end.

Now looking at our financial position. Helmerich & Payne had cash and short-term investments of approximately $350 million at September 30, 2022 versus $333 million at June 30, including availability under our revolving credit facility, our liquidity remains at approximately $1.1 billion. We again expect changes in the components of working capital to reduce cash in fiscal 2023 as was the case in fiscal '22, whenever revenue increases as we expect with pricing uplifts across the fiscal year, rising receivables create a use of cash.

Fiscal Q1 is expected to experience lower cash flow from operations in the following quarters due to the planned rig reactivations and ongoing price increases. Earlier, I mentioned the cash flow generation expected for fiscal 2023. As John mentioned, moving through fiscal '23, our returns as measured in ROIC should be back in line with levels seen in 2014 and earlier.

These levels are expected to be well into the double digits as an average across the fiscal year and, therefore, in excess of our estimated weighted average cost of capital. As announced in our October press release, subject to ongoing Board approval, we plan to pay supplemental dividends across fiscal 2023 of approximately $100 million, which is approximately 50% of the remaining cash flow after CapEx and after our established base dividend. So in essence, this results in a full 2/3 of cash flow after CapEx returned to shareholders with 1/3 retained for flexibility.

As of today, with this flexible $100 million unallocated, we would expect to end the fiscal year with between $430 million and $490 million of cash and $60 million to $120 million of net debt. However, that is not the intention. Rather, going forward, we will reassess this allocation throughout the year with an eye toward opportunistic share repurchases, additional dividends and before accretive investment opportunities.

That said, our current plans for capital allocation look to further add to our long-standing priority of returning cash to shareholders and to add to the roughly $2.7 billion of cash that we have returned to shareholders during the past 10 years through dividends and share repurchases. That concludes our prepared comments for the fourth fiscal quarter.

Let me now turn the call over to Ashley for questions.

(Operator Instructions) We'll take our first question from Derek Podhaizer with Barclays.

I just wanted to first ask about the leading edge day rates and moving the average up to that level. So maybe you can just talk to me about how long that lag is to close that gap. I think you just guided to about 30,000 of day rates for the fiscal 1Q. -- leading-edge sounds like it's in the upper 30s or has hit 40,000. Just maybe walk us through how you can roll the term contracts over to reach that level and when we can see it in the financials?

This is John. I don't have the exact timing on that. Dave or Mark may have more color on that. But you nailed it. That is our focus, and we are seeing the results of that quarter-over-quarter, we'll continue to move those averages, both in the spot and term closer to that leading edge, and that's really our focus. That's where the real opportunity set is there. Mark, do you have any further color on that?

Well, our average spot is about what is the about are...

Yes. And that's not including -- that's day rate. Revenues...

Revenue and average is about 37%. Yes. So the delta, if you think of legacy ancillary and technology, all in, our revenue per day at the spot is about 37,000 a day. Our term, as we mentioned earlier, is about 30% revenue per day, and I think leading edge is getting up to around 41,000 a day.

And Derek, that's why we mentioned the 65 rates we have rolling off between now and March 31, kind of give you an idea of that progression and how you can model that into the year.

Got you. Okay. That's helpful. I want to jump over to international. Obviously, a lot of moving pieces going on. Can you walk us through your -- you just exited about 12 rigs you said, where do you expect to exit fiscal 2023? Just trying to get an idea of the cadence of the rig activations between Argentina, Middle East and Australia. And then what can we expect as far as earnings and margin power in the international region, how much that's going to contribute to total company?

Well, I think we just guided to somewhere around 13 rigs at the end of December with the one we plan to add in Argentina. But as you move through fiscal '23, we'll have an eye on the 3 remaining Flex 3s in Argentina that will be upgraded to super-spec and trying to deploy those. Importantly, we also have one that's moving to Australia, as we mentioned, and that looks to spud in the summer of '23 in -- and it was originally by the way, earmarked to go to the Middle East hub, but it's been redirected for this Tamboran opportunity.

And then the 6 rigs that we have mentioned that are being recommissioned and converted to walking in the second half of the year, those are all geared towards various tenders we're participating in with an eye towards the Middle East. There are several burgeoning Gulf Coast country unconventional plays where those rigs can differentiate.

And we've been working, as we have talked about in successive quarters on these calls, we've been working in increasing our brand presence in the region, which was aided by our transaction in partnership with ADNOC. And we are actively participating and looking to differentiate in the unconventional plays and gas and oil, I think, was a real focus in several of these countries currently on natural gas.

Okay. So anything on what we could expect from these rigs when they're fully contributing on as far as a daily margin, just the earnings power around these rigs?

I think the earnings power on these rigs will be equivalent with what you're seeing today and more. And again, that's yet another year away before those 6 would actually be beginning to turn to the right. So more to come, but we certainly target returns for these just like we do for everything in the high to mid-teens.

And we will go next to David Smith with Pickering Energy.

Just a quick follow-up on that last question. About the 6 rigs you plan to export from the stack U.S. fleet. I think you said those are targeted to tenders you've been on. I imagine there's a fairly long lead time in this. And there's -- so we've be thinking about fiscal '24 as when we could start seeing a contribution from those?

That's correct, David. That's correct.

Appreciate it. And just regarding the commentary about the base and the supplemental dividend, representing about 2/3 of expected cash flow less CapEx in fiscal '23. Is that roughly 2/3 figure indicative of your longer-term thinking on returning cash via the basin supplemental dividend?

David, this is really -- our 2023 plan is really just that. It's our 2023 plan because that's the -- you've heard me say before, it's hard to see much past a quarter in this business, and we're forecasting out a year and making that commitment for 2023. So our intent -- our hope is that in future fiscal years will have similar, if not even better, but that's kind of we're -- this is just for 2023. Anything to add?

Yes, I would just add, David, is the -- John and I, the management team and discussions with the Board. We said we think through several capital allocation criteria. And I'll just kind of tick through these. One is maintaining a minimum liquidity for operations, which is less than the cash we had on hand at September 30.

We have -- with a view that as we have with our conservative stewardship of the balance sheet and the Vietorisk management and also positioning for optionality, we prefer $200 million minimum cash balance. Second, consideration in our capital allocation criteria as we have long committed to our creditors in our fiscal stewardship is assessing cash generation to ensure we maintain a leverage of less than 2x, less than 2 turns.

Third, as you know, we're opportunistic for accretive investment opportunities with, as I said, just a minute ago, in a previous question, with mid- to high-teen returns individually and that contribute to our goals for consolidated ROIC in the same range. Fourth, opportunistic in using the Evergreen $4 million share repurchase authorization. Example of that would really be last November and December a year ago when we believed there was a dislocation in our share price, which led us to repurchase shares in the first quarter of fiscal '22.

And then finally, I would say, towards the end of the fiscal year, in consideration of all the aforementioned, if an excess cash balance remains then management and the Board will consider further additional dividends. And then as John said, then we'll move forward and develop the fiscal '24 budget which would reassess forward fiscal year cash generation above CapEx at that time and above the established base dividend to work with the Board to figure out the 24 capital allocation plan.

We take our next question from Luke Lemoine with Piper Sandler.

John, if we look at your 16 reactivations this fiscal year, I imagine there's a few things going on with incremental activity, some operators upgrading the super-spec rigs and maybe some market share gains as well from other super-spec great providers. Can you talk about these buckets a little more and maybe which of these you see as the main driver?

Luke, I think there's -- as we said, there are several drivers. I think you heard us the 16, the ones that we have committed are mostly large public companies, which was really has been our expectation. I think most people's expectations as the private companies have contributed a lot of rigs, active rigs to the fleet over the last couple of years.

So we think most of that will be directed towards the larger players. We think most of that will also be in the Permian, but not all. I mean we do have Haynesville and I think there may be an Eagle Ford, there's some North Dakota opportunities. I think we may even have an Oklahoma rig in there. But I think the majority of it is focused in the Permian. But going back to our discussion earlier, so much of the demand out there is being provided through this -- through at least in our fleet.

I would have to suspect other companies are on the same is really a function of the churn that we're seeing quarter-over-quarter. And so a lot of that demand is satisfied there. So as an example, if what we found is on the 16 that we -- there was more churn than expected. It could be that we wouldn't put all 16 of those rigs out into the market because we're satisfying that demand through other means. So does that answer your question?

Well, I guess, yes, partly, but maybe you talked about churn a lot and now just to, do you think maybe it's some of the churn in other people's fleets that you're gaining some market share? Or do you think these are purely incremental rigs from the large public players?

Yes, that's a good point. It's a mix. We've had -- some of these rigs are incremental. Some of these rigs are replacement. But as you know, if we replace another peer's rig, that rig then moves over and satisfied demand somewhere else as you just start thinking about these points of demand in the market, those are going to be satisfied in many cases from other rigs that are rolling off of one to the other. I think 2/3 are incremental and then the other 1/3 are replacement for what we have committed right now.

Okay. Got it. And then maybe just kind of on the overall market outlook, with 2/3 of this being incremental, you have about 1/4 of the overall market share. Do you think that's kind of indicative of overall market growth or hard to say?

I think it's really hard to say at this point. We feel like that there will be modest growth, obviously, on our -- from our rig count, we would consider that to be modest. -- where, as we've said, and probably said it maybe too many times, but we're really focused on capital discipline and making certain that we don't put a rig in the market that is the excess rig, if you will, just based on the demand criteria, we can utilize a rig that's hot that's rolling off from somebody else, then we can do that.

But it's really hard to say. I mean, obviously, if you just use the math on our market share, adding 40 to 50 rigs back over the next, what, 13, 14 months, I think is reasonable, but it's just really hard -- as you know, it's really hard to call from this point.

And we'll take our next question from Arun Jayaram with JPMorgan.

You guys mentioned that about 2/3 of the 16 rigs that you plan to reactivate have been contracted. John, you mentioned that you're looking for a minimum of 2 years in terms of commitment to put those into the field. Just wondering if you could give us a sense of where pricing is for term contracts relative to the leading edge that you pegged in the low 40s?

On the term contracts, the majority of those rigs are in some support of a performance-based contract in that 2-year term contract. And our expectation would be that again, assuming performance, and that's what we're focused on with our customers. We're going to be close -- we're going to be closer to that leading-edge pricing with those term contracts. Again, they're performance-based, but we've been able to deliver on those. So we feel good about the pricing.

So in other words, we're not taking -- and really, it's not just for those rigs, but it's all rigs. We're not entering into a term contract at a discount. We're entering into a term contract at leading edge or close to leading edge with the opportunity to get some additional revenue and margin based on performance and sharing in those savings.

Great. Just a follow-up, John, on the company's call international growth strategy. I think 1/4 of your CapEx this year or fiscal year will be focused on the international side of the business. As we look forward to fiscal year 2024, can you give us maybe frame some ranges of potential rigs that you could see deployed internationally. And as you think about participating in tenders, are you participating with other service companies or talk to us about the bidding dynamics, particularly as we think about the Middle East?

Well, Arun, you know the market very well in the Middle East, and these are long plays. And so thinking about 2024, I think it really makes a lot of sense. We were recently in Abu Dhabi here a few weeks -- 2, 3 weeks ago at Adapt Conference and a lot of excitement there.

And of course, we're excited about opportunities in Abu Dhabi and Saudi, Oman other countries that have shown some interest. And the majority of that is for unconventional resource play development. And of course, nobody has drilled more horizontal wells than H&P. So I think we have a lot to add there. So these tenders take a long time you have to have a lot of patients. But again, it's a long game, and that's what we're focused on. Mark, do you have anything you would...

No, I agree, John, that as you mentioned, unconventional. And I would just add, maybe put in the room as we look at these various tenders we're participating in and a bona fide participation in them and with many of these NOCs and boots on the ground sales folks in the region there that we've invested in the last couple of years. We're looking at some of these tenders with scale. So not 1 or 2 rigs, but 4, 5, 6 rigs, and that's each, and that's why you see our investment this year is setting us up for margin generation accretive to the company in '24 and beyond.

Right. And just maybe just a quick follow-up here is just on the frame agreement with ADNOC drilling, how does that work relative to the -- your companies -- your H&P specific opportunities how that work in Abu Dhabi?

Well, we've delivered the 8 rigs that we talked about that we've sold. We have an agreement where we're working with them on conventional projects. And so that continues to trend well. And we really don't have a whole lot to -- more to add to that right now. But there will be more to come -- more to come as we go through the next several quarters.

We'll take our next question from Waqar Syed with ATB Capital Markets.

John, the rig needed for unconventional drilling in the Middle East, is it a similar type of super spec rig, is 1,500 horsepower enough for that type of drilling? Or do you need to have a bigger rig? Could you maybe elaborate on the type of thing that will be needed?

Now that's exactly right. Our -- really, our Flex 3, both Flex3 SCID and Flex 3 walking rigs are both very well suited for the wells that we've looked at, at this point. And those rigs have performed very, very well in Abu Dhabi in the past when we were drilling previously. I don't think they were doing any horizontal. They were doing a lot of really long directional type wells. But no, they're very well suited for that work, and I think our national oil companies we're talking to are very excited about the opportunity.

Great. And then, Mark, your EBITDA margins in the international business were about 1% or so. In the past, a couple of years ago, they were as high as low 20%. Do you -- where do you think the EBITDA margins could go through this fiscal year?

But if you look at the fiscal year, starting off with a higher rig count to begin with, I think you'll certainly see year-over-year margin expansion. But I'll just caveat that, that even that margin expansion is even with a bit of a drag on some of the expenses we're incurring in setting up the Middle East and Australia, more focused on the Middle East Hub. But even with that, you're going to see margin expansion this year.

Could you quantify those expenses in the Middle East and Australia?

Now -- no, it's really early days in Australia. There's a lot of planning work that's happening for setting up operations on the ground in the summer of '23. I will tell you, as I mentioned earlier, that rig that's targeted to be shipped in January. Much of the work was already incurred on that in fiscal '22. But as it relates to the Middle East hub, quite a bit of work is happening, and we'll just see that to continue to be a little bit of a drag on -- as I said, the margin expansion for the segment is up simply because of the number of units working and getting better and better pricing on those units, it's just a scale thing. And we think that will do nothing but growth through time.

Yes. Well, Waqar, that -- we're excited about that opportunity, as Mark said. And there's a lot of experience on the ground there. Tamboran has guys that have done a lot of work on unconventional plays in the U.S., and we're excited to be working with them. We think it's a great opportunity, again, it's really, really early days, but it looks like an exciting play.

Absolutely. And then just final question, John. Would your contracting strategy change given that you now have like this capital allocation program and you've got this $1.94 type dividend that you're planning for fiscal year 2023?

No. Waqar, I'm not completely following the change of contracting strategy.

Well, I'm just saying like you have about, let's say, 2 rigs contracted right now, and that's pretty much consistent with what you've had over the last 1 year or so. And like 50% over the next 6 months. I'm just thinking that would you carry a higher number of rigs under term contracts in the -- for the subsequent 6 months going forward? Are you okay with that despite having a higher level of dividend that you'll be paying out?

Yes. We're targeting in that 50% to 60% range, and that really hasn't been driven by the dividend level. I mean the cash that we're generating is as Mark described, we should have excess cash outside of that plan. Mark, what would you add?

I would just say today, we talked about so many of them were early over between now and in the end of March in the prepared comments, Waqar, -- and the average term length day is probably 10, 11 months. So you have to just remember that, by and large, those -- so many of the term contracts that have existed from rollovers back from the super-spec upgrading time frame or really in the 1-year calendar period. That's why so much of our capital allocation plan as a result of the customers and they're really adhering to their annual budgets.

And so that really gives us underpinning our confidence for the annual supplemental plan. But overall, where we are in this cycle and due to that -- due to not having new builds, we do not have any significant investments in super-spec upgrades and due to customers living in an annual fiscal year budget as opposed to cash flow, you see a lot of 12-month terms.

[Much different] cycle, Waqar, than what we have experienced previously because obviously, we're not looking at new builds. We don't have all that capital outlay. And as we've said, we're really focused on this and margin generation, it's a margin cycle, not really a growth cycle. So we're excited about that.

We'll go next to Marc Bianchi with Cowen.

Mark, I think in your prepared remarks, you mentioned a $1,500 sequential benefit to margin. Was that meant for the March quarter? And then does that kind of continue in the subsequent quarters? Was that the message just because of how the contracts kind of roll off and reprice?

It's actually happening for this December quarter and then each of the next couple. But that's exactly right, Mark. That's what I was talking about is that rollover when you pull the lower term out else the average of the remaining on term.

Okay. But the benefit in the December quarter should be better than the $1,500 if I'm just trying to back into back into what's implied by the $250 million to $270.

Yes, you're in from Yes, it's a little bit better.

Okay. And the implication of this sort of leading-edge 40,000 or so and John, you made the comment about it being the term contract being performance-based and being able to kind of get to that 40,000. I mean, if your costs are 16.5%, then we're getting into the 23,500 kind of margin per day at some point once the fleet rolls. I mean if I just carry this out, it seems like you could be there in the beginning of March 2024. I mean is that the right way to think about where this ultimately goes? Or are there other puts and takes that you'd call out that maybe we shouldn't model it that way?

Well, those are the numbers. And we are -- we are -- again, we're focused, as I said earlier, on getting the averages for spot and term closer to leading edge. What we haven't said is how many rigs are closer to that leading edge. That isn't our focus. And so again, the numbers are the numbers. So...

Yes. Okay. Well, just one more for me on the walking upgrades. So just doing 6 for North America at this point, what are the -- what's the scenario where you would be doing back on that sort of 1 per month cadence? And should we think of -- what should we think about that beyond 2023? Are you going to kind of turn the whole fleet over to walking at some point? Or what's the long-term thought on that?

Well, Marc, as you've heard us say before, I mean, you just look at the fleet that's out there working today and the lion's share of that are Flex 3 skid rigs. And you're right, the 6 rigs, we've done 6 conversions to walking, but that's really a function of customer demand. We have -- we've actually had more demand for Flex 3 skid rigs and we have walking rigs.

So it's all going to be dependent upon customer demand, the types of wells that are being drilled. It's really a wide range. The 6 -- the other 6 rigs that we are converting, those are the ones that we're talking about sending to the Middle East. So we're going to do what is in the best interest of satisfying customer demand and what's in the best interest of shareholders. But there sure won't be a conversion to the entire fleet. Again, there's customers out there that all they use are Flex 3 skid rigs.

And at this time, I'll turn the call back over to John Lindsay for any closing remarks.

Thank you, Ashley, and thanks, again, to all of you for joining us today. We know there's a lot going on. There's a lot of priorities that are going on out there at this time of the year. So we really appreciate your time. I'll tell you again that as the H&P team and I've said it, and I'll continue to say it, we're laser-focused on delivering value to customers and shareholders. We aim to deliver value to customers through top-tier performance, safety and reliability and to our shareholders we're going to continue to focus on improving our rig margins and growth and our returns on capital. So thank you again for your time, and have a great day.

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