Thank you, George. Good morning and welcome to Transocean's second quarter 2022 earnings conference call. A copy of our press release covering financial results, along with supporting statements and schedules, including reconciliations and disclosures regarding non-GAAP financial measures are posted on our website at deepwater.com. Joining me on this morning's call are Jeremy Thigpen, Chief Executive Officer; Keelan Adamson, President and Chief Operating Officer; Mark Mey, Executive Vice President and Chief Financial Officer; and Roddie Mackenzie, Executive Vice President and Chief Commercial Officer. During the course of this call, Transocean management may make certain forward-looking statements regarding various matters related to our business and company that are not historical facts. Such statements are based upon current expectations and certain assumptions and therefore are subject to certain risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our SEC filings for our forward-looking statements and for more information regarding certain risks and uncertainties that could impact our future results. Also, please note that the Company undertakes no duty to update or revise forward-looking statements. Following Jeremy and Mark's prepared comments, we will conduct a question-and-answer session with our team. During this time, to give more participants an opportunity to speak, please limit yourself to one initial question and one follow-up. Thank you very much. I will now turn the call over to Jeremy.

Thank you, Alison, and welcome to our employees, customers, investors, and analysts participating in today's call. It has certainly been an eventful three months since our last update. Commodity prices have exhibited considerable volatility with the magnitude of the existing supply-demand imbalance, energy security concerns, and the inability of swing producers to meet their production targets, all driving prices higher, while concern around potential demand destruction due to either or both high gasoline prices and/or a dramatic slowdown in global economies pushing prices lower. That said, perspective is important. While we have experienced volatility, commodity prices have remained within a range that is still extremely healthy for offshore development. Indeed, the outlook for our industry-leading assets and services is the most promising it has been in many, many years. Globally, we continue to face an energy crisis resulting from years of underinvestment in oil and gas reserves replacement and production growth, as energy companies reacted to significant pressure from investors to maintain capital discipline and pressure from investors, activists, and politicians to rapidly transition to lower carbon energy sources and renewables. As a consequence, the long-term replacement of hydrocarbon reserves has consistently fallen short of production levels, and consequently, depleted global inventories driving barrel and end product prices to near record highs. This consistent shortfall in production leads us to conclude that we're in the early stages of a sustainable recovery. Now to our results and a summary of global offshore drilling markets and fixtures. As reported in yesterday's earnings release for the second quarter, Transocean delivered adjusted EBITDA of $245 million on $722 million in adjusted revenue, resulting in an adjusted EBITDA margin of approximately 34%. These solid results were once again driven by strong operating performance as we delivered fleet uptime in excess of 96% and revenue efficiency of 97.8%, which was supported by strong contractual bonus conversion. Notwithstanding our solid operating performance, in the backdrop of a strengthening offshore drilling market, illustrated by our recent fleet status report and the fixtures we announced last night. As we look to the back half of the year, we are likely to experience some gaps between contracts, which could impact our utilization as our customers grapple with temporary supply chain challenges that hamper their near-term ability to secure key capital equipment and consumables needed to conduct their campaigns in a timely manner. However, we expect these delays to gradually diminish over the next 12 to 18 months. Mark will provide some additional color when he updates our guidance in a few minutes. Let's now turn to the fleet and our recent fixtures. We continue to see steady improvement in day rates, contract terms, and the utilization of the global offshore drilling fleet, particularly the high specification assets Transocean owns and operates. First in the Gulf of Mexico, we signed an agreement with a major operator for two years on the Deepwater Conqueror and direct continuation of the current program at a leading edge rate of $440,000 per day, with up to an additional $39,000 per day for MPD integrated services and our technology products. The contract represents approximately $321 million in firm backlog. That is in addition to the amount disclosed on our fleet status report. In Norway, Equinor exercised two one-well options on the Spitsbergen at a rate of $305,000 per day, extending the current firm term through June 2023. We also signed a nine-well contract with Equinor for the transition Spitsbergen at a rate of $335,000 per day commencing October 2023. The agreement contains a provision for two one-well options at a rate of $375,000 per day. And similar to many of our contracts in Norway, we have the opportunity to earn a healthy bonus percentage in addition to the base day rate. In the UK as disclosed in the fleet status report, we secured a one-well contract plus options with NEO energy and Harbour energy for the Paul B. Loyd at a rate of $175,000 per day. Subsequent to the release of the fleet status report, the first option well was exercised to commence a direct continuation of the rig's current program, adding approximately $17.5 million to our backlog. The firm period now stands at 200 days. If all options are exercised, this will keep the rig busy through April 2024. Down in Brazil, the Deepwater Mykonos was awarded a 435-day contract at a rate of approximately $364,000 per day in direct continuation of the current program. Also in Brazil, subsequent to the release of our fleet status report, the Petrobras 10,000 received a 5.8-year contract at $399,000 per day escalating annually to $462,000 per day. The rate does not include an additional fee for the customer's anticipated use of our patented dual activity technology, which remains valid through May 2025. The contract commences directly following the end of the current term in October 2023 and adds an estimated $915 million to our backlog. In India, Reliance Industries awarded an estimated 86-day contract extension plus up to four option wells for the KG1 at a local market-leading rate of $330,000 per day. The firm work extends the contract through July 2023. And if all options are exercised, the campaign will extend through April 2024. This leading edge rate in India reinforces that the industry recovery has moved beyond the harsh environment in the Golden Triangle and is truly extending to other regions across the globe. In total, I'm pleased to share we have added approximately $1.3 billion in backlog since the release of our fleet status report. Next, I'd like to take some time to discuss energy security and the important role we play. Though the alarming conflict between Russia and Ukraine was the latest catalyst for recognition of this critical situation, it opened the entire world's eyes to the increasingly fragile state of global energy supply. In fact, the consistent and systemic marginalization of companies involved in the production of hydrocarbons has significantly contributed to the situation we find ourselves in today. This is now more apparent than ever. Recently, OPEC+ agreed to moderately increase production at the behest of large oil-consuming countries, chiefly the United States. OPEC+ producers, however, appear to have little or no spare capacity, raising the question of whether these actions will reduce short and long-term oil prices or simply contribute to sustained volatility. Indeed, one of the leading energy research consultancies estimates the spare capacity within OPEC+ is just 1% of global demand, the lowest level since the inception of its assessments in 2012. Without additional drilling, it is estimated that non-OPEC production will decline by 9 million barrels per day by 2025 and 20 million barrels per day or 41% by 2030. Additionally, according to Rystad Energy's 2022 review, global recoverable oil reserves now total an estimated 1.6 trillion barrels, which is a drop of almost 9% since last year, and 152 billion barrels fewer than the 2021 total. For those who are willing to look beyond political advocacy and honestly assess the empirical data, there is no doubt that hydrocarbons will continue to play an important role in supplying the world's energy for the foreseeable future. As an example, electricity generation is highly dependent upon hydrocarbons. According to BP's most recent statistical review of world energy, 63% of global electricity is generated by fossil fuels, with over a quarter of total supply coming from oil and natural gas. Moreover, 84% of global primary energy consumption comes from fossil fuels, with 57% from oil and natural gas. With that, we believe the case is clear that E&P companies will continue to engage in exploration and development work to meet worldwide demand and replenish diminishing reserves. This is especially true in the offshore basins requiring our assets and services where recoverable reserve levels are high and carbon intensity is relatively low. With sustained constructive commodity prices, the economics of offshore projects remain compelling for continued development. The concept of energy expansion rather than transition means we need to develop and deploy all energy sources and technologies without ideological bias. The production of hydrocarbons or renewables must happen in concert to meet even the most conservative estimates of global energy demand. As such, it's not surprising that we continue to see a rapid tightening of the offshore market for high-capability drilling assets unfolding across multiple regions with committed drillship utilization remaining above 90%, and we believe further tightening is on the horizon. In June, Rystad revised its year-over-year offshore deepwater E&P investment growth projection to 28%, which is double its March projection, driven by higher service costs and additional anticipated requirements in Brazil, Ghana, West Africa, and Australia. The trend of day rate fixtures also supports our positive view on the outlook for offshore drilling. Most recently, we saw Equinor contract a competitor's asset with nearly $90 million in upfront payments to partially cover mobilization, reactivation, and upgrade costs. Bringing the total equivalent day rate to about $600,000 per day, a move we take as recognition by one of our largest customers that the market is growing increasingly tight for the highest specification drillship fleet. And the latest projection by Fernley shows active utilization for the global 6th and 7th Gen fleet over 97% with rate projections clearly crossing the $400,000 per day threshold, which we certainly validated with the fixtures we announced last night. Taking a closer look at the global market environment, the Gulf of Mexico is expected to remain tight through the end of the year. While fixtures in the region have slowed a bit this quarter, we anticipate contract activity will accelerate over the next two quarters. Our estimates show more than 10 programs yet to be awarded that are set to commence between now and the second quarter 2023. Importantly, direct negotiations continue to dominate as a result of market tightness, and we are seeing improved contractual terms, higher day rates, and longer durations. Several operators are urgently looking to secure 7th Gen assets for multi-year agreements in the U.S. Gulf of Mexico, some of which have not appeared on any of the annual reports today. There have also been constructive developments in the 20K market. You likely know Shell recently assumed 51% ownership of the project formerly known as North Platte, which they have since renamed Sparta. The agreement for another drilling contractor vessel that was initially contracted by Total Energies for North Platte was recently terminated, and we believe we are now very well positioned to secure this work if and when the project is re-tendered. As a reminder, in addition to the 20K well control equipment that will be installed on the Deepwater Titan in the Deepwater Atlas, both rigs are also outfitted with industry-leading 1,700 short-term hoisting capability, a feature that is unique to these two rigs and has the potential to enable our customers to run fewer casing strings, presenting a significant time and cost savings. On that note, I'm proud and pleased to report that the Deepwater Atlas was delivered from the shipyard in June and is expected to arrive in the U.S. Gulf of Mexico in Q4, where contract preparations will be completed prior to commencement of our main contract with Beacon Offshore Energy. While on the subject of new builds, we are on pace to accept delivery of the Deepwater Titan later this year. In Latin and South America, substantial contracting activity is ongoing and the region continues to drive the largest recovery in incremental deepwater rig demand. Specifically in Brazil, there are 10 opportunities comprising in excess of 21 years of demand. One of these opportunities is the Petrobras multiyear pool tender, an opportunity we believe could draw up to seven rigs from the global fleet into Brazil, which would obviously require several reactivations. Tender submissions are due within several weeks, and we believe our long-standing relationships, robust support infrastructure, and strong operational performance in the region make us highly competitive for this work. In addition to the Petrobras prospects, medium to long-term opportunities with IOCs and other NOCs, including Equinor, Shell, Petronas, and Total Energies are expected to commence in 2023 and 2024. As we mentioned on our last call, there are no high specification available floaters in the region. Therefore, rigs from other areas will be required to meet additional demand, which we anticipate will remain strong over the next several years as Brazil continues on its journey to double production by 2030, which would make the country the world's fifth-largest crude exporter. In West Africa and the Mediterranean, we remain very encouraged by floater demand, as we expect over 20 programs to be awarded and commence within the next 18 months. A number of these programs are multi-year opportunities with multiple NOCs and IOCs. As an example, E&I is currently tendering for two red lines each at 18 months commencing between Q1 and Q2 next year. Similarly, Shell is looking to secure an asset for its campaign in Egypt that could keep that rig off the market for up to two years. If the demand materializes as anticipated, we could see around 15 rig years of work awarded in the next several quarters. In Asia Pacific, we continue to observe demand in various jurisdictions with limited risk supply. If the demand materializes as we expect, we could see a significant increase in day rates from what we have observed in the past several years. In fact, ONGC has demand for more than four rig years of work in India that could absorb three rigs. Additional demand in India and Australia is expected to increase in mid 2023 and early 2024, which would result in a regional rig shortage at this time driving higher day rates as assets will need to be mobilized from other regions to fill this demand. Moving to the harsh environment market in Norway, we expect relative softness and activity to continue through the end of the year, with a sizeable uptick in sanctioning and contracting activity anticipated by year-end as the Norwegian tax incentives expire in December. We think this will ultimately lead to a sold-out market in 2024, as current active utilization is already at 88%, up from 82% last quarter. And it's important to note that we also expect to see several of those assets leave the harsh environment market for higher margin work in benign environments, which will further strain supply. Consequently, we believe rates in Norway will continue the upward trajectory we've seen with our recent fixture on the Spitsbergen. In fact, the latest third-party projections suggest we could see base day rates excluding bonus potential exceed $400,000 per day in some of the next fixtures being announced. In summary, our outlook remains very constructive, supported by the upward trajectory of fixtures, customer conversations, industry analyst reports, and market projections for commodity supply, demand, and balances. All indications point to a further tightening of the market as we continue to see increasingly healthy day rates posted across all regions as well as longer terms. As we approach rate levels that meaningfully support strengthening our balance sheet, we reaffirm the message we have conveyed for the last several years: liquidity and deleveraging is of paramount importance to us. Therefore, we are actively managing our portfolio of high specification floating rigs to fit the best combination of rate and term and will not reactivate an asset if it does not fit within our broader strategy, including generating an appropriate return on the full cost of reactivation. We continue to evaluate opportunities for our stacked fleet on a case-by-case basis and will mobilize them if and when it makes sense in light of market conditions and if we are convinced that it will enhance shareholder value. The future of our core business is very bright, and we expect offshore drilling to comprise the majority of value for investors for the foreseeable future. However, we fully embrace the need to, wherever possible, utilize our numerous competencies, assets, and talented employees to support the expansion of our business and to transition to a lower carbon future. In this regard, we continue to support several ongoing initiatives, including our collaboration with our partner Ocean Minerals to help support the sustainable collection of seabed minerals required for high-capacity batteries, such as those found in electric vehicles. We continue to leverage our significant offshore energy experience in ways that contribute to the development of non-traditional energy sources. However, to be clear, as we and other leaders in our industry have indicated, offshore drillers will continue to play a vital role in the production of hydrocarbons for the foreseeable future. For Transocean, our core offshore drilling business will be the foundation that allows us to develop adjacent opportunities and lower carbon energy sources while at the same time remaining focused on improving our balance sheet to ensure that we have the liquidity to support our business. As the industry leader in ultra-deepwater and harsh environment drilling, we are continuing to invest in innovations that make our fleet safer, more reliable, and more efficient, creating value for our customers and shareholders. On our last call, we shared progress on the implementation of a robotic riser system on one of our rigs in the U.S. Gulf of Mexico. I'm pleased to report that we have installed this system on a second ship in the Gulf and are currently working to outfit a third rig in the coming quarters. As a reminder, the robotic riser system automates activities around the rotary table during riser operations, which improves the safety of the operation for our personnel and ultimately improves the consistency and efficiency of our operations. We are also working with our customers on a fuel additive that optimizes fuel consumption, thereby lowering emissions and reducing costs. Fuel tests utilizing the additives suggest fuel consumption can be reduced by up to 6% depending upon engine loads. To date, we have worked with two customers in the U.S. Gulf of Mexico to adopt and implement the additive and are in conversations for additional implementations. In conclusion, our industry-leading backlog, which I would like to emphasize grew last quarter and with our announcements last night will certainly grow again this quarter, along with the steadily increasing cash flow producing ability of our fleet enables us to maintain Transocean's position as the market leader for ultra-deepwater and harsh environment drilling. As we move further along the curve in the industry recovery, we will continue providing safe, reliable, and efficient operations for our customers, while simultaneously focusing on leveraging our balance sheet to safeguard and create value for our shareholders.

Thank you, Jeremy, and good day to all. During today's call, I will briefly recap our second quarter results and then provide guidance for the third quarter as well as an update of expectations for full year 2022. Let's now provide an update on our liquidity forecast for the end of 2023. As reported in a press release, which includes additional detail on our results, for the second quarter of 2022, we reported a net loss attributable to controlling interest of $68 million or $0.10 per diluted share. During the quarter, we generated adjusted EBITDA of $245 million and improved our EBITDA margin to approximately 34%. We also generated cash flow from operations of approximately $41 million. Looking closer at our results, during the second quarter we delivered adjusted contract drilling revenues of $722 million at an average day rate of $358,000. Revenues above our previous guidance reflect better-than-forecasted uptime, higher bonus conversion, and higher reverses reimbursable. Operating and maintenance expense in the second quarter was $433 million. This is less than guidance primarily due to the timing of certain maintenance activities. Turning to cash flow and the balance sheet. We ended the second quarter with total liquidity of approximately $2.5 billion, including unrestricted cash and cash equivalents of approximately $729 million, approximately $400 million of restricted cash for debt service, and $1.3 billion from our undrawn revolving credit facility. Before updating guidance, I'm pleased to share that we have closed an amendment to our revolving credit facility, extending its maturity through June of 2025. The extended RCF has a capacity of $774 million through mid-June 2023 and $600 million thereafter through maturity. This extension provides additional certainty and enables us to maintain sufficient financial flexibility as the global drilling market continues to improve. Through an accordion feature, the amended facility also permits us to increase the aggregate amount of capital by up to $250 million. I'll now provide an update on expectations for our third quarter and full year financial performance. For the third quarter of 2022, we expect adjusted contract drilling revenue to be approximately $670 million based on an average fleet-wide revenue efficiency of 96.5%. The quarter-over-quarter decrease is largely attributable to low utilization, chiefly due to idle time on the Asgard development rig. For the full year 2022, we are anticipating adjusted contract drilling revenue to be approximately $2.6 billion, down from our prior guidance by $100 million due to the additional idle time mentioned above. To provide context for the aforementioned idle time, that is not a result of a lack of contract drilling opportunities, as witnessed by our recent fleet status report and the $1.2 billion of contract backlog announced yesterday, but rather primarily a result of supply chain challenges faced by customers. For example, in the Gulf of Mexico, several operators have been struggling to access tubulars and consumables for the work construction activities. And in Norway, similar supply chain issues are coupled with lengthy approval cycles that have been hampering near-term activity. While these delays are disappointing, they did not alter our mid-to-longer term outlook. We expect third quarter O&M expense to be approximately $464 million. The quarter-over-quarter increase is primarily attributable to the timing of maintenance projects across the fleet. For the full year 2022, we anticipate O&M expense to be approximately $1.7 billion. We continue to experience pressure on employee costs and increased pricing from our vendors. A significant portion of our maintenance expenditures falls under our comprehensive services agreements. These CSAs contain provisions capping annual inflation and limit exposure to rising costs. Additionally, longer-term customer contracts provide cost escalation protection. Finally, with the expected rapid increase in activity, we may experience a shortage of qualified personnel and resulting labor inflation over the next 12 to 18 months. We expect G&A expense for the third quarter to be approximately $45 million and approximately $175 million for the full year. Net interest expense for the third quarter is forecasted to be approximately $98 million. This includes capitalized interest of approximately $21 million. For the full year, we estimate incurring net interest expense of approximately $395 million, including capitalized interest of approximately $72 million. Capital expenditures and capital additions including capitalized interest, are forecast to be approximately $150 million for the third quarter. This represents approximately $100 million for our newbuild drillships, predominantly the Deepwater Atlas, and $50 million of maintenance CapEx. Cash taxes are expected to be approximately $11 million for the second quarter and approximately $34 million for the year. Our expected liquidity at December of 2023 is projected to be approximately $1.1 billion, reflecting $550 million remaining capacity of our revolving credit facility, and including restricted cash of approximately $280 million, which is primarily reserved for debt service, and anticipated secured financing of a second eighth generation drillship, Deepwater Titan. This liquidity forecast includes an estimated 2022 capital expenditures and capital additions of $1.2 billion and a 2023 CapEx expectation of $200 million. The 2022 CapEx includes $1.1 billion related to our newbuild and $60 million for maintenance CapEx. As always, our guidance excludes speculative rig reactivations or upgrades. In conclusion, strengthening the balance sheet and extending our liquidity runway remain our priority. The extension of our revolving credit facility is the first in a series of actions we will take to address our balance sheet and financial flexibility. We also anticipate continuing to utilize the at-market equity offering program, from which we have received aggregate cash proceeds of $367 million as of June 30. As you're probably aware, our first and highly successful ATM equity program is limited to $40 million. We fully anticipate with new authorization for another $400 million. As always, you can expect us to continue to prudently manage our share capital and opportunistically access capital markets as and when we believe it makes sense. Rate levels have not comfortably surpassed levels necessary to generate cash flow sufficient to meaningfully support deleveraging our balance sheet over time. This remains our primary priority and as we expand accordingly, creates value for all shareholders.

Hey, this is Roddie, I'll take that one. Look, I appreciate the compliment there. But I think what I would first like to say is that those may look like market-leading day rates, but I really believe those are very savvy customers who are moving to get access to the right assets in the right timeframe. So yes, they look like they're leading the market today, but I don't think that's going to be the case in the next 6 to 12 months. I think the truth of the matter is very simply as we look at things around the world, especially in the specification of the assets, the customers are moving extremely quickly. So it used to be that you saw six to nine months, sometimes between when we were answering tenders and when a fixture would be made. That's not the case now. The majority of the negotiations we are involved in are direct negotiations and not part of a tender. So that really helps as we're beginning to see commitments being made within the space of weeks and a couple of months rather than quarters. So I think you're going to see an acceleration there because especially for the high specification units, there simply is very, very little availability. So that bodes very well. And I think the second part of the question was around the conversations with the customers. I think, again, it's an increased sense of urgency, but also making sure that they have access to the right iron for their prospects. So of course, having higher specification units is important in that realm. So, I think you'll see a real push at the moment for access to the existing fleet, especially the high-spec stuff because we really are close to being sold out completely, and that means reactivations and moving cold assets back into the market, which, obviously, is not as desirable as picking up one of the highest spec rigs in the world that's hot and already performing very well.

Yes, Thomas, this is Keelan and very good question. I think our guidance remains the same. We're probably looking at over 12 to 18 months for a reactivation based on the limitations in the supply chain at this time. Obviously, we're hoping that that will improve as the situation stabilizes. From a labor point of view, that is something that the industry is used to and we're used to the simplicity that exists in our business. And you'll find that most of the drilling contractors in our space, including ourselves, are prepared from a recruiting process to our training and our competency development programs. So, we have access to people we can recruit and develop those people in a very timely fashion. So, yes, it's a challenge, but I think the bigger challenge we have right now is the supply chain side, which is still around 12 to 15 months.

I think sometimes we forget when the markets are rolling higher or how quickly it can roll higher. I guess Roddie, this is probably for you. As you think about the different basins and just kind of piggybacking on the press releases from last night, is there any way to characterize the type of duration demand you're seeing in different basins, i.e., as we look at opportunities in West Africa? Are those more term duration work versus what you're seeing and maybe Gulf of Mexico? Any way to kind of parcel that out, where as we look ahead, could we see some more multiyear contracts or is it really broad-based?

Historically, when we see day rates moving up, contract terms and conditions are also improving in the background. So I'm curious if you can give us any color around EMCs, particularly around bonus opportunities, non-productive time allowances, and cancellation provisions?

Just a follow-up. I think you mentioned some of this briefly in the prepared remarks. But should we still expect some concrete news on the Petrobras eight rig tender in the near term and just kind of any thoughts on your involvement in that? It would be very helpful.

Thanks, Mark. George, we're now ready to take questions. As a reminder to the participants, please limit yourself to one initial question and one follow-up question.