Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist you in understanding our financial position as of March 31, 2023, and our results of operations for the three months ended March 31, 2023 and 2022. The discussion should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2022, which was filed with the SEC on March 31, 2023. The results of operations for the interim periods are not necessarily indicative of the operating results for the full fiscal year or any future periods.
Overview
We are an international offshore drilling company focused on operating a fleet of modern, high specification drilling units. Our principal business is to contract drilling units, related equipment and work crews, primarily on a dayrate basis, to drill oil and gas wells for our customers. Through our fleet of drilling units, we provide offshore contract drilling services to major, national and independent oil and gas companies, focused on international markets. Additionally, for third party owned drilling units, we provide operations and marketing services for operating and stacked rigs, construction supervision services for rigs that are under construction and preservation management services for rigs that are stacked.
The following table sets forth certain current information concerning our offshore drilling fleet as of May 12, 2023:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Year Built |
|
Water Depth Rating (feet) |
|
|
Drilling Depth Capacity (feet) |
|
|
Location |
|
Status |
Owned Rigs: |
|
|
|
|
|
|
|
|
|
|
|
|
Jackups |
|
|
|
|
|
|
|
|
|
|
|
Topaz Driller |
|
2009 |
|
|
375 |
|
|
|
30,000 |
|
|
Egypt |
|
Operating |
Soehanah |
|
2007 |
|
|
375 |
|
|
|
30,000 |
|
|
Indonesia |
|
Operating |
Drillships (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Platinum Explorer |
|
2010 |
|
|
12,000 |
|
|
|
40,000 |
|
|
India |
|
Operating |
Tungsten Explorer |
|
2013 |
|
|
12,000 |
|
|
|
40,000 |
|
|
Namibia |
|
Operating |
Third Party Owned Rigs: |
|
|
|
|
|
|
|
|
|
|
|
|
Drillships |
|
|
|
|
|
|
|
|
|
|
|
|
Polaris |
|
2008 |
|
|
10,000 |
|
|
|
37,500 |
|
|
India |
|
Operating |
Aquarius |
|
2008 |
|
|
10,000 |
|
|
|
35,000 |
|
|
High Seas |
|
Mobilizing |
Capella |
|
2008 |
|
|
10,000 |
|
|
|
37,500 |
|
|
Mozambique |
|
Operating |
Jackups |
|
|
|
|
|
|
|
|
|
|
|
|
Emerald Driller |
|
2008 |
|
|
375 |
|
|
|
30,000 |
|
|
Qatar |
|
Operating |
Sapphire Driller |
|
2009 |
|
|
375 |
|
|
|
30,000 |
|
|
Qatar |
|
Operating |
Aquamarine Driller |
|
2009 |
|
|
375 |
|
|
|
30,000 |
|
|
Qatar |
|
Operating |
(1)The drillships are designed to drill in up to 12,000 feet of water and are currently equipped to drill in 10,000 feet of water.
Recent Developments
Redemption of the 9.25% First Lien Notes
On February 3, 2023, the Company issued a notice of full conditional redemption to the then existing recordholders (the “Notice of Full Conditional Redemption”) of the remaining portion of the 9.25% First Lien Notes then outstanding after the partial redemption consummated in December 2022. The balance of the 9.25% First Lien Notes was redeemed in full on March 6, 2023 with proceeds derived from the issuance of the 9.50% First Lien Notes (as discussed below). See “Note 5. Debt” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report for further information regarding the Notice of Full Conditional Redemption. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2 of this Quarterly Report.
9.50% First Lien Notes Offering
On February 14, 2023, the Company priced an offering of $200.0 million in aggregate principal amount of the 9.50% First Lien Notes and entered into a purchase agreement with several investors pursuant to which the Company agreed to sell the 9.50% First Lien Notes (the “9.50% First Lien Notes Offering”) to the purchasers in reliance on an exemption from registration provided by Section 4(a)(2), Rule 144A and/or Regulation S of the Securities Act. On March 1, 2023, the Company closed the sale of the 9.50% First Lien Notes. See “Note 5. Debt” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report for further information regarding the 9.50% First Lien Notes Offering. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2 of this Quarterly Report.
27
Geopolitical and Market Instability Caused by the Ongoing Russo-Ukrainian War, Inflationary Pressures and Other Macroeconomic Conditions
Over the past 18 months, global oil prices have experienced a robust recovery resulting in the strongest annual performance (on a price-per-barrel basis) since 2012. During 2022, specifically, Brent crude reached a high of approximately $125.00 per barrel in March 2022 although Brent crude ultimately settled at approximately $85.00 per barrel on the last day of trading in December 2022. Through the first quarter of 2023, Brent crude reached a high of approximately $88.00 per barrel and settled at approximately $80.00 per barrel on the last date of trading in March 2023. While our management anticipates that oil and gas prices will remain elevated in the near-term as compared to prices exhibited during the last five years, price volatility is still expected to continue as a result of, among other factors, (i) adverse macroeconomic conditions, including inflationary pressures, potential recessionary conditions, and supply chain impediments and constraints, (ii) changes in oil and gas inventories, (iii) global market demand, (iv) geopolitical instability, armed conflict and social unrest, including the Russo-Ukrainian War, the associated response undertaken by western nations, such as the implementation, expansion and renewal of broad sanctions, the potential for retaliatory actions on the part of Russia and the overall impact on OPEC+ countries' ability to achieve production targets in the near- and long-term, (v) potential future disagreements among OPEC+ countries regarding the supply of oil, (vi) the potential for increased production and activity from U.S. shale producers and non-OPEC countries driven by the current oil prices, and (vii) the presence and/or resurgence of COVID-19, including the transmission and presence of highly contagious and newly discovered variants, and therefore, the Company cannot predict how long oil and gas prices will remain stable or further increase, if at all, or whether they could reverse course and decline.
The Russo-Ukrainian War, in particular, has led to, and will likely continue to lead to, geopolitical instability, disruption and volatility in the markets in which we operate. It is not possible at this time to predict or determine the ultimate consequences of the Russo-Ukrainian War, which could include, among other things, additional sanctions, greater regional instability, embargoes, geopolitical shifts and other material and adverse effects on macroeconomic conditions. However, such macroeconomic conditions, including inflationary pressures and potential recessionary conditions (and actions taken or being contemplated by central banks and regulators in an attempt to reduce, curtail and address such pressures and conditions), changes in energy policy, supply chain constraints and limitations, unpredictable financial markets and currency exchange rates, and hydrocarbon price volatility, are likely to continue for the foreseeable future. To the extent the Russo-Ukrainian War and other adverse macroeconomic conditions, including those set forth above, continue (or exacerbate), it could have a lasting impact in the near- and long-term on the (i) operations and financial condition of our business and the businesses of our critical counterparties and (ii) global economy.
While our management is actively monitoring the foregoing events and its associated financial impact on our business, it is uncertain at this time as to the full magnitude that volatile and uncertain oil and gas prices will have on our financial condition and future results of operations.
The Aquadrill Merger and the Termination of Certain Agreements
VHI previously entered into a framework agreement with Aquadrill LLC (“Aquadrill”) on February 9, 2021 (the “Framework Agreement”), and, certain subsidiaries of VHI (the “VHI Entities”) subsequently entered into a series of related management and marketing agreements (collectively, the “Marketing and Management Agreements” and together with the Framework Agreement, the “Framework, Management and Marketing Agreements”) with certain subsidiaries of Aquadrill (collectively, the “Aquadrill Entities”). Pursuant to the Framework, Management and Marketing agreements, the VHI Entities agreed to provide certain marketing and operational management services with respect to the Capella, Polaris and Aquarius floaters. As of May 12, 2023, the Capella and the Polaris were performing drilling services for clients under their respective drilling contracts, while the Aquarius was mobilizing to Norway.
Pursuant to the terms of the Framework, Management and Marketing Agreements, the Company is eligible to receive the following fees associated with the management and marketing of the Aquadrill rigs: (i) first, the Company is to be paid a fixed management fee of $2,000, $4,000, $6,000 and $10,000 per day to manage a cold stacked rig, warm stacked rig, reactivating rig or operating rig, respectively (provided, that, certain discounts are to be provided on the management fee associated with cold stacked rigs to the extent there are more than one such rigs managed by the Company for Aquadrill); (ii) second, there are certain bonus/malus amounts that are applied to the fixed management fee that are contingent on whether the actual expenditures for a particular rig that is stacked, mobilizing, being reactivated or preparing for a contract exceed or come in under budget; (iii) third, the Company is eligible to receive a marketing fee of 1.5% of the effective day rate of a drilling contract secured for the benefit of Aquadrill; (iv) fourth, the Company is eligible to earn a variable fee equal to 13% of the gross margin associated with managing an operating rig for Aquadrill; and (v) lastly, all costs incurred by the Company are reimbursed by Aquadrill (other than incremental overhead costs incurred by Vantage). In accordance with the terms of the Framework, Marketing and Management Agreements, Aquadrill may also terminate such agreements upon 90 days’ notice (the “Notice Termination Period”), subject to certain conditions set forth in such agreements.
On December 23, 2022, Seadrill Ltd. announced that it had entered into a merger agreement with Aquadrill LLC (“Aquadrill”), pursuant to which Aquadrill would become a wholly owned subsidiary of Seadrill Ltd. (the “Aquadrill Merger”), and on April 3, 2023, Seadrill Ltd. announced that it had closed the Aquadrill Merger. On April 10, 2023, we received a notice of termination (the “Termination Notice”) of the management agreement (the “Aquarius Management Agreement”) and marketing agreement with respect to the Aquarius
28
(the “Aquarius Marketing Agreement,” and together with the Aquarius Management Agreement, the “Aquarius Agreements”), and the marketing agreements with respect to the Capella and Polaris (the “Capella and Polaris Marketing Agreements”), in each case as a result of the Aquadrill Merger. Accordingly, after the Notice Termination Period lapses, we will no longer be managing or marketing the Aquarius nor eligible to earn management fees under the Aquarius Management Agreement as of July 9, 2023. Notwithstanding the termination of the Aquarius Agreements and the Capella and Polaris Marketing Agreements, certain provisions survived such termination and, therefore, to the extent that a drilling contract(s) is secured and executed in respect of outstanding bids or tenders for the Aquarius, Polaris and/or Capella, we will still be eligible to earn the marketing fee in respect of such secured and executed contracts, as well as in respect of existing drilling contracts. Moreover, as the management agreements with respect to the Capella and Polaris remain in effect as of the date hereof, we continue to manage and operate those rigs for Seadrill Ltd. (and for the oil and gas clients under their respective drilling contracts) and therefore, remain eligible to receive the management and variable fees described immediately above. Nevertheless, there is no guarantee that such arrangements will remain in place in the near- and long-term and any further terminations of such arrangements could have a material impact on our financial condition and future results of operations.
Impact of the COVID-19 Pandemic
The global spread of COVID-19, including its highly contagious variants and sub-lineages, has caused widespread illness and significant loss of life, leading governments across the world to impose and re-impose severely stringent and extensive limitations on movement and human interaction, with certain countries, including those where we maintain significant operations and derive material revenue, implementing quarantine, testing and vaccination requirements. These governmental reactions to the COVID-19 pandemic, as well as changes to and extensions of such approaches, have led to, and could continue to result in, uncertain and volatile economic activity worldwide, including within the oil and gas industry and the regions and countries in which we operate.
Any resurgence of COVID-19 could pose significant risks and challenges worldwide, and while the Company has previously managed, and continues to actively manage, the business in an attempt to mitigate any ongoing and material impact from the spread of COVID-19, management anticipates that our industry, and the world at large, will need to continue to operate in, and further adapt, to the current environment for the foreseeable future.
Business Outlook
Expectations about future oil and gas prices have historically been a key driver of demand for our services. Over the past 18 months, global oil prices have experienced a robust recovery resulting in the strongest annual performance (on a price-per-barrel basis) since 2012. During 2022, specifically Brent crude oil reached a high of approximately $125.00 per barrel in March 2022; although Brent crude ultimately settled at approximately $85.00 per barrel on the last day of trading December 2022. Through the first quarter of 2023, Brent crude reached a high of approximately $87.00 per barrel and settled at approximately $80.00 per barrel on the last day of trading in March 2023. The relatively elevated prices exhibited in 2022 and thus far in 2023 have been due to, among other factors, the (i) OPEC+ countries’ agreements to (x) reduce production by almost 10 million barrels per day in 2020, two million barrels per day during the fourth quarter of 2022, and an additional approximately 1.7 million barrels per day in April 2023, and (y) boost production in portions of 2022, but only in measured steps, (ii) development, efficacy, availability and utilization of vaccines for COVID-19, (iii) reopening of global economies, (iv) injection of substantial government monetary and fiscal stimulus and (v) ongoing energy supply crisis driven by a shortage of fuel within recovering economies and anticipated extreme weather across Europe and northeast Asia, along with years of under investment in oil reserve replacement, all of which has been exacerbated by global turmoil, and political and market instability caused by the Russo-Ukrainian War.
Notwithstanding the elevated prices of oil exhibited during the prior 18 month period, market volatility and uncertainty largely remain as Brent oil prices ranged from a high of approximately $125.00 per barrel in March 2022 to approximately $72.00 barrel in March 2023, and the oil and gas industry continues to be materially impacted and shaped by external factors which have influenced its overall development and recovery, including global macroeconomic challenges resulting from inflationary pressures and potential recessionary conditions, as well as geopolitical and market instability caused by the Russo-Ukrainian War. In response to these challenges, OPEC+ agreed on October 5, 2022 to a production cut of two million barrels per day, an amount which constituted approximately 2.0% of overall global oil production. While the U.S. could release additional barrels from its strategic oil reserve in response to these production cuts, the actions taken by OPEC+ could contribute to, among other things, greater inflationary pressures and sharp price increases to oil and gas in the near- and long-term. Moreover, the recent actions undertaken by OPEC+ in April 2023 to further cut production by approximately 1.7 million barrels per day (accounting for approximately 3.7% of global demand) could exacerbate these concerns. In addition, the Russo-Ukrainian War has caused, and could continue to cause for the foreseeable future, significant instability, disruption, uncertainty and volatility in the hydrocarbon industry and the global markets at large. Further geopolitical developments could occur, including a possible agreement relating to Iran’s nuclear deal and the subsequent suspension of U.S. sanctions in Iran (which could result in, among other things, the influx of Iranian crude oil into the global markets), any of which could significantly impact our business and operations. With higher crude oil prices there is the potential for increased production from U.S. shale producers and non-OPEC countries, which could lead to significant increases in the overall global oil and gas supply, and result in reduced commodity prices.
29
In addition, the opening of economies, supply chain constraints and limitations occurring throughout the world and across various industries, and the injection of significant levels of governmental monetary and fiscal stimulus to avoid a recession during the peak of the COVID-19 pandemic, collectively contributed to the highest level of inflation in decades across the U.S., the United Kingdom, Europe and the global community at large. In the U.S., for example, the Consumer Price Index reached a 40-year high in June 2022. While such rates are expected to ease incrementally in the near-term, our operations could be materially and adversely impacted by any exacerbation to global inflation, including in the form of increases in personnel costs and the prices of goods and services required to operate our rigs. Given that we enter into fixed dayrate contracts that have contractual terms with minimal adjustments to account for rising inflation, the majority (if not all) of these costs would be borne by us. While we are currently unable to estimate the ultimate impact of inflation, including the associated impact on the prices of goods and services, our costs could rise in the near-term and materially impact our profitability and overall financial condition.
Furthermore, central banks and regulators across the world have raised, and they could continue to raise, interest rates in an attempt to gain further control over and reduce inflation in their respective jurisdictions. Such efforts being undertaken by central banks and regulators could tip the global economy into a recession, which could materially and adversely impact demand for oil and gas and, in the process, demand for our services.
As a result of such volatility, disruption, instability and uncertainty, operators have faced, and will generally continue to face, difficulties when attempting to definitively plan their capital budget programs for the near- and long- term.
Backlog
The following table reflects a summary of our contract backlog coverage of days contracted and related revenue as of March 31, 2023 based on information available as of such date:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Days Contracted |
|
Revenues Contracted (in thousands) |
|
|
2023 |
|
2024 |
|
Beyond |
|
2023 |
|
|
2024 |
|
|
Beyond |
|
Backlog |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jackups |
43% |
|
0% |
|
0% |
|
$ |
32,518 |
|
|
$ |
— |
|
|
$ |
— |
|
Drillships |
93% |
|
4% |
|
0% |
|
$ |
127,732 |
|
|
$ |
6,580 |
|
|
$ |
— |
|
Third party owned rigs (1) |
60% |
|
50% |
|
20% |
|
$ |
46,105 |
|
|
$ |
3,053 |
|
|
$ |
219 |
|
(1)These amounts include: (i) a fixed management fee paid to us pursuant to the applicable management agreement; (ii) a marketing fee paid to us pursuant to the applicable marketing agreement; (iii) a fixed management fee paid to us pursuant to the applicable EDC Support Services Agreements; and (iv) contract backlog attributable to rigs owned by third parties where we enter into contracts directly with customers and lease the rigs through bareboat charters from the rig owners. However, these amounts exclude any variable fee payable to us pursuant to the applicable management agreement. The terms of the bareboat charters are consistent with the management agreements, resulting in the same financial impact to us had the rigs remained under the management agreements.
Results of Operations
Operating results for our contract drilling services are dependent on three primary metrics: available days; rig utilization; and dayrates. The following table sets forth this selected operational information for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2023 |
|
|
2022 |
|
Jackups |
|
|
|
|
|
|
Rigs available |
|
|
2 |
|
|
|
2 |
|
Available days (1) |
|
|
90 |
|
|
|
180 |
|
Utilization (2) |
|
|
100.0 |
% |
|
|
60.3 |
% |
Average daily revenues (3) |
|
$ |
58,182 |
|
|
$ |
74,295 |
|
Deepwater |
|
|
|
|
|
|
Rigs available |
|
|
2 |
|
|
|
2 |
|
Available days (1) |
|
|
180 |
|
|
|
180 |
|
Utilization (2) |
|
|
62.8 |
% |
|
|
98.8 |
% |
Average daily revenues (3) |
|
$ |
192,492 |
|
|
$ |
165,159 |
|
Sold Rigs/Held for Sale (4) |
|
|
|
|
|
|
Rigs available |
|
|
— |
|
|
|
3 |
|
Available days (1) |
|
|
— |
|
|
|
270 |
|
Utilization (2) |
|
N/A |
|
|
|
41.5 |
% |
Average daily revenues (3) |
|
N/A |
|
|
$ |
66,813 |
|
30
(1)Available days are the total number of rig calendar days in the period, excluding rigs under bareboat charter contracts to third parties.
(2)Utilization is calculated as a percentage of the actual number of revenue earning days divided by the available days in the period. A revenue earning day is defined as a day for which a rig earns dayrate after commencement of operations.
(3)Average daily revenues are based on contract drilling revenues divided by revenue earning days. Average daily revenue will differ from average contract dayrate due to billing adjustments for any non-productive time, mobilization fees and demobilization fees.
(4)Each of these rigs were classified as held for sale on our Consolidated Balance Sheets during the Current Period and at December 31, 2022, up to the date of the EDC Sale.
For the Three Months Ended March 31, 2023 and 2022
Net loss attributable to shareholders for the Current Period was $2.3 million, or $0.17 per basic share, on operating revenues of $77.1 million, compared to net loss attributable to shareholders for the Comparable Period of $14.9 million, or $1.14 per basic share, on operating revenues of $58.3 million.
31
The following table is an analysis of our operating results for the three months ended March 31, 2023 and 2022:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
Change |
|
|
|
2023 |
|
|
2022 |
|
|
$ |
|
|
% |
|
(unaudited, in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling services |
|
$ |
47,917 |
|
|
$ |
44,913 |
|
|
$ |
3,004 |
|
|
|
7 |
% |
Management fees |
|
|
2,120 |
|
|
|
1,103 |
|
|
|
1,017 |
|
|
|
92 |
% |
Reimbursables and other |
|
|
27,035 |
|
|
|
12,315 |
|
|
|
14,720 |
|
|
|
120 |
% |
Total revenues |
|
|
77,072 |
|
|
|
58,331 |
|
|
|
18,741 |
|
|
|
32 |
% |
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
66,555 |
|
|
|
43,933 |
|
|
|
22,622 |
|
|
|
51 |
% |
General and administrative |
|
|
4,831 |
|
|
|
6,582 |
|
|
|
(1,751 |
) |
|
|
-27 |
% |
Depreciation |
|
|
11,049 |
|
|
|
11,295 |
|
|
|
(246 |
) |
|
|
-2 |
% |
Loss on EDC Sale |
|
|
3 |
|
|
|
— |
|
|
|
3 |
|
|
** |
|
Total operating costs and expenses |
|
|
82,438 |
|
|
|
61,810 |
|
|
|
20,628 |
|
|
|
33 |
% |
Loss from operations |
|
|
(5,366 |
) |
|
|
(3,479 |
) |
|
|
(1,887 |
) |
|
|
54 |
% |
Other (expense) income |
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
49 |
|
|
|
4 |
|
|
|
45 |
|
|
n/m |
|
Interest expense and financing charges |
|
|
(5,558 |
) |
|
|
(8,504 |
) |
|
|
2,946 |
|
|
|
-35 |
% |
Other, net |
|
|
322 |
|
|
|
(775 |
) |
|
|
1,097 |
|
|
|
-142 |
% |
Total other expense |
|
|
(5,187 |
) |
|
|
(9,275 |
) |
|
|
4,088 |
|
|
|
-44 |
% |
Loss before income taxes |
|
|
(10,553 |
) |
|
|
(12,754 |
) |
|
|
2,201 |
|
|
|
-17 |
% |
Income tax (benefit) provision |
|
|
(7,978 |
) |
|
|
1,438 |
|
|
|
(9,416 |
) |
|
|
-655 |
% |
Net loss |
|
|
(2,575 |
) |
|
|
(14,192 |
) |
|
|
11,617 |
|
|
|
-82 |
% |
Net income (loss) attributable to noncontrolling interests |
|
|
(289 |
) |
|
|
706 |
|
|
|
(995 |
) |
|
|
-141 |
% |
Net loss attributable to shareholders |
|
$ |
(2,286 |
) |
|
$ |
(14,898 |
) |
|
$ |
12,612 |
|
|
|
-85 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling services |
|
$ |
26,988 |
|
|
$ |
44,913 |
|
|
$ |
(17,925 |
) |
|
|
-40 |
% |
Management fees |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
** |
|
Reimbursables and other |
|
|
6,422 |
|
|
|
5,183 |
|
|
|
1,239 |
|
|
|
24 |
% |
Total revenue |
|
|
33,410 |
|
|
|
50,096 |
|
|
|
(16,686 |
) |
|
|
-33 |
% |
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
27,722 |
|
|
|
36,438 |
|
|
|
(8,716 |
) |
|
|
-24 |
% |
General and administrative |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
** |
|
Depreciation |
|
|
10,639 |
|
|
|
10,856 |
|
|
|
(217 |
) |
|
|
-2 |
% |
Total operating costs and expenses |
|
|
38,361 |
|
|
|
47,294 |
|
|
|
(8,933 |
) |
|
|
-19 |
% |
Income (loss) from operations |
|
|
(4,951 |
) |
|
|
2,802 |
|
|
|
(7,753 |
) |
|
n/m |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Managed Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling services |
|
$ |
20,929 |
|
|
$ |
— |
|
|
$ |
20,929 |
|
|
** |
|
Management fees |
|
|
2,120 |
|
|
|
1,103 |
|
|
|
1,017 |
|
|
|
92 |
% |
Reimbursables and other |
|
|
20,613 |
|
|
|
7,132 |
|
|
|
13,481 |
|
|
|
189 |
% |
Total revenue |
|
|
43,662 |
|
|
|
8,235 |
|
|
|
35,427 |
|
|
|
430 |
% |
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
38,833 |
|
|
|
7,495 |
|
|
|
31,338 |
|
|
|
418 |
% |
General and administrative |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
** |
|
Depreciation |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
** |
|
Total operating costs and expenses |
|
|
38,833 |
|
|
|
7,495 |
|
|
|
31,338 |
|
|
|
418 |
% |
Income from operations |
|
|
4,829 |
|
|
|
740 |
|
|
|
4,089 |
|
|
|
553 |
% |
n/m = not meaningful |
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Revenue: Total revenue increased $18.7 million due primarily to an increase in operating activities in the Current Period as discussed below.
32
Drilling Services Revenue: Contract drilling revenue decreased $17.9 million for the Current Period as compared to the Comparable Period. The decrease in our contract drilling revenue was primarily the result of the Tungsten Explorer being in between drilling contracts during the Current Period as it commenced its current contract on March 2, 2023, lower contract drilling revenue as we operated three less jackup rigs, which were included in the EDC Sale, and the Topaz Driller as the rig is operating under a bareboat charter in the Current Period as compared to operating under a drilling contact in the Comparable Period. Reimbursables and other revenue increased 24% in the Current Period as compared to the Comparable Period primarily as a result of bareboat charter fees earned on the Topaz Driller, offset by lower reimbursable revenue as a result of the changes in drilling contracts (as discussed immediately above).
Managed Services Revenue: Contract drilling revenue increased $20.9 million in the Current Period due to the Polaris, which is operated by the Company. Management fees increased $1.0 million in the Current Period as compared to the Comparable Period primarily due to the management of the rigs included in the EDC Sale as well as deepwater floaters owned by Aquadrill. Reimbursables and other revenue increased $13.5 million in the Current Period as compared to the Comparable Period is primarily as a result of the management of the deepwater floaters owned by Aquadrill and the rigs included in the EDC Sale.
Consolidated Operating Costs: Total operating costs increased 51% due primarily to an increase in operating activities in the Current Period as discussed below.
Drilling Services Operating Costs: Drilling Services operating costs decreased 24% in the Current Period as compared to the Comparable Period primarily as a result of changes to certain of our drilling contracts (as discussed in Drilling Services Revenue above). The Comparable Period includes a net gain of approximately $1.9 million related to the sale of various assets.
Managed Services Operating Costs: The increase in Managed Services operating costs in the Current Period as compared to the Comparable Period is the result the management of certain deepwater floaters (as discussed in “Managed Services Revenue” above).
General and Administrative Expenses: Decreases in general and administrative expenses for the Current Period as compared to the Comparable Period were primarily due to decreased labor costs offset by higher professional fees. Non-cash share-based compensation expense included in “General and administrative expenses” was immaterial for each of the Current Period and Comparable Period.
Depreciation Expense: Depreciation expense is primarily related to rigs owned by us included in our Drilling Services segment. The Managed Services segment does not currently own depreciable assets. Depreciation expense for the Current Period is in line with the Comparable Period.
Interest Income: Increases in interest income for the Current Period as compared to the Comparable Period were due primarily to higher cash investments during the Current Period.
Interest Expense and Financing Charges: Interest expense and financing charges includes non-cash deferred financing costs totaling approximately $0.3 million and $0.4 million for each of the Current Period and Comparable Period, respectively.
Other, Net: Our functional currency is USD; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than USD. These transactions are re-measured in USD based on a combination of both current and historical exchange rates. Net foreign currency exchange gain of approximately $0.3 million and loss of approximately $0.8 million was included in “other, net,” for the Current Period and Comparable Period, respectively.
Income Tax Provision: Our annualized effective tax rate for the Current Period is 97.91% based on estimated annualized ordinary profit before income taxes excluding income tax discrete items. Our annualized effective tax rate for the Comparable Period was negative 17.51%, based on estimated annualized loss before income taxes excluding income tax discrete items.
Our income taxes are generally dependent upon the results of our operations and the local income taxes in the jurisdictions in which we operate. In some jurisdictions, we do not pay taxes or receive benefits for certain income and expense items, including interest expense and disposal gains or losses. In other jurisdictions, we recognize income taxes on a net income basis or a deemed profit basis.
Liquidity and Capital Resources
Sources and Uses of Liquidity
Our anticipated cash flow needs, both in the short- and long-term, may include, among others: (i) normal recurring operating expenses; (ii) planned and discretionary capital expenditures; (iii) repayments of interest; and (iv) certain contractual cash obligations and commitments. We may, from time to time, redeem, repurchase or otherwise acquire our outstanding 9.50% First Lien Notes through open market purchases, tender offers or pursuant to the terms of such securities.
We currently expect to fund our cash flow needs with cash generated by our operations, cash on hand or proceeds from sales of assets. As of March 31, 2023, we believe we maintain adequate cash reserves and are continuously managing our actual cash flow and cash forecasts. Accordingly, management believes that we have adequate liquidity to fund our operations for the twelve months
33
following the date our Consolidated Financial Statements are issued and therefore, have been prepared under the going concern assumption.
As of March 31, 2023, we had working capital of approximately $116.0 million, including approximately $69.9 million of cash available for general corporate purposes. Scheduled debt service consists of interest payments through December 31, 2023 of approximately $8.7 million. We anticipate capital expenditures through December 31, 2023 to be between approximately $12.8 million and $15.7 million. As our rigs obtain new contracts, we could incur reactivation and mobilization costs for these rigs, as well as additional customer requested equipment upgrades. These costs could be significant and may not be fully recoverable from the customer. Based on our expected levels of activity, incremental expenditures through December 31, 2023 for special periodic surveys, major repair and maintenance expenditures and equipment re-certifications are anticipated to be between approximately $18.3 million and $22.3 million. As of March 31, 2023, we maintained letters of credit outstanding in the amount of $11.4 million. Such amount includes a letter of credit in respect of a $3.6 million bank guarantee (the “Historical Bank Guarantee”) supporting obligations under one of our former drilling contracts to which we no longer are a party as it was included in the EDC Sale. The Historical Bank Guarantee and other bank guarantees were canceled and the related letters of credit were released in April 2023. As of May 12, 2023, we had letters of credit outstanding in the amount of $5.9 million.
The following table includes a summary of our cash flow information for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
(unaudited, in thousands) |
|
2023 |
|
|
2022 |
|
Cash flows (used in) provided by: |
|
|
|
|
|
|
|
Operating activities |
|
$ |
(18,142 |
) |
|
$ |
(8,205 |
) |
|
Investing activities |
|
|
(843 |
) |
|
|
(3,799 |
) |
|
Financing activities |
|
|
4,541 |
|
|
|
— |
|
Changes in cash flows from operating activities are driven by changes in net loss during the relevant periods (see the discussion of changes in net loss above in “Results of Operations” of this Part I, Item 2).
Cash flows from investing activities in the Comparable Period include net proceeds of $3.1 million derived from the sale of various assets.
Cash flows from financing activities in the Current Period include (i) net proceeds of $190.1 million derived from the issuance of the 9.50% First Lien Notes, (ii) $180.0 million redemption of the 9.25% First Lien Notes as described in “Note 5. Debt” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report, and (iii) $5.3 million payment of dividend equivalents as described in “Note 6. Shareholders’ Equity” in the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report.
The significant elements of the 9.50% First Lien Notes are described in “Note 5. Debt” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2.
We enter into operating leases in the normal course of business for office space, housing, vehicles and specified operating equipment. Some of these leases contain options that would cause our future cash payments to change if we exercised those options.
Commitments and Contingencies
We are subject to litigation, claims and disputes in the ordinary course of business, some of which may not be covered by insurance. Information regarding our legal proceedings is set forth in “Note 8. Commitments and Contingencies” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2.
There is an inherent risk in any litigation or dispute and no assurance can be given as to the outcome of any claims. We do not believe the ultimate resolution of any existing litigation, claims or disputes will have a material adverse effect on our financial position, results of operations or cash flows.
Critical Accounting Policies and Accounting Estimates
The preparation of unaudited financial statements and related disclosures in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Our significant accounting policies are included in “Note 2. Basis of Presentation and Significant Accounting Policies” of the “Notes to the Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report. These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements. While management believes current estimates are appropriate and reasonable, actual results could materially differ from those estimates. We
34
have discussed the development, selection and disclosure of such policies and estimates with the audit committee of the Board of Directors.
Our critical accounting policies are those related to property and equipment, impairment of long-lived assets and income taxes. For a discussion of the critical accounting policies and estimates that we use in the preparation of our consolidated financial statements, see “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates” in Part II of our Annual Report on Form 10-K for the year ended December 31, 2022, which was filed with the SEC on March 31, 2023. During the Current Quarter, there were no material changes to the judgments, assumptions or policies upon which our critical accounting estimates are based.
Recent Accounting Pronouncements: See “Note 2. Basis of Presentation and Significant Accounting Policies” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report for further information. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2.