Sanctioned Low Cost Tupper Montney Natural Gas Development

HOUSTON--(BUSINESS WIRE)--Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the fourth quarter ended December 31, 2020, including a net loss attributable to Murphy of $172 million, or $1.11 net loss per diluted share. Adjusted net loss, which excludes discontinued operations and other one-off items, was $14 million, or $0.09 net loss per diluted share.

Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary exclude noncontrolling interest. ¹

Highlights for the fourth quarter include:

• Sanctioned low cost, capital efficient Tupper Montney development
• Produced 149 thousand barrels of oil equivalent per day, in line with guidance
• Generated adjusted EBITDAX of $271 million, or $19.77 per barrel of oil equivalent sold
• Continued on-time and on-budget execution of major Gulf of Mexico projects

Highlights for full year 2020 include:

• Preserved liquidity of $1.7 billion, including $311 million of cash at year-end
• Maintained capital discipline with full year accrued capital expenditures of $712 million, excluding King’s Quay floating production system
• Decreased full year G&A costs by 40 percent from 2019, establishing a baseline for a continued lower cost structure
• Established a greenhouse gas emissions intensity reduction goal of 15 to 20 percent by 2030 from 2019 levels, excluding Malaysia
• Instituted COVID-19 protocols, resulting in an offshore infection rate at half the industry average while maintaining all project timelines
• Maintained a reserve life index of more than 11 years with 57 percent proved developed reserves

During and subsequent to the fourth quarter:

• Entered into additional crude oil hedges for 2021 and 2022, bringing the total contracted position to 45 thousand barrels of oil per day and 20 thousand barrels of oil per day, respectively
• Committed to fixed price forward sales contracts related to the Tupper Montney asset for calendar years 2021 through 2024

“We quickly responded to the major pullback in commodity prices by drastically reducing our capital budget and cost structure while adjusting our operational plans, and continued supporting capital allocation to our major offshore projects. Our efforts resulted in strong liquidity, cash on hand and paying a dividend to our shareholders,” stated Roger W. Jenkins, President and Chief Executive Officer.

FOURTH QUARTER 2020 RESULTS

The company recorded a net loss, attributable to Murphy, of $172 million, or $1.11 net loss per diluted share, for the fourth quarter 2020. Adjusted net loss, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, was $14 million, or $0.09 net loss per diluted share for the same period. The adjusted net loss from continuing operations excludes the following primary after-tax items: $137 million mark-to-market loss on crude oil derivative contracts and $12 million mark-to-market loss on contingent consideration. Details for fourth quarter results can be found in the attached schedules.

Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations attributable to Murphy was $246 million, or $17.96 per barrel of oil equivalent (BOE) sold. Adjusted earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) from continuing operations attributable to Murphy was $271 million, or $19.77 per BOE sold. Details for fourth quarter EBITDA and EBITDAX reconciliations can be found in the attached schedules.

Fourth quarter production averaged 149 thousand barrels of oil equivalent per day (MBOEPD) with 55 percent oil and 62 percent liquids. Production was impacted by two subsea equipment issues in the Gulf of Mexico late in the quarter, totaling approximately 3,700 BOEPD of unplanned downtime. The subsea repairs are ongoing, with a return to full production expected during the first quarter 2021. Our onshore assets were able to offset the impact of the subsea matters due to strong well performance.

Details for fourth quarter production can be found in the attached schedules.

FULL YEAR 2020 RESULTS

The company recorded a net loss, attributable to Murphy, of $1.1 billion, or $7.48 net loss per diluted share, for the full year 2020. The company reported an adjusted loss, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, of $193 million, or $1.25 net loss per diluted share. This includes after tax impairments of $854 million. Details for full year 2020 results can be found in the attached schedules.

Production for the full year averaged 164 MBOEPD and consisted of 57 percent oil and 64 percent liquids volumes. Details for 2020 production can be found in the attached tables.

FINANCIAL POSITION

The company had $2.8 billion of outstanding long-term, fixed-rate notes at the end of fourth quarter 2020. The fixed-rate notes had a weighted average maturity of 6.8 years and a weighted average coupon of 5.9 percent. Murphy also had $200 million drawn on the $1.6 billion senior unsecured credit facility at year-end 2020.

As of December 31, 2020, Murphy had approximately $1.7 billion of liquidity, comprised of $1.4 billion available under the $1.6 billion senior unsecured credit facility and approximately $311 million of cash and cash equivalents.

COMMODITY HEDGE POSITIONS MITIGATE CASH FLOW VOLATILITY

The company employs commodity derivative instruments to manage certain risks associated with commodity price volatility and underpin capital returns associated with certain assets. During and subsequent to the fourth quarter, Murphy layered on hedges to protect cash flow with the execution of West Texas Intermediate (WTI) fixed price swaps, as detailed in the table below.

As of January 26, 2021

To support the sanctioned Tupper Montney development, the company also entered into fixed price forward sales contracts for physical delivery at the AECO hub in Canada, with the current contracts as follows:

As of January 26, 2021

YEAR-END 2020 PROVED RESERVES

Murphy’s preliminary year-end 2020 proved reserves were 697 million barrels of oil equivalent (MMBOE), consisting of 36 percent oil and 41 percent liquids. Total proved reserves were 13 percent lower than at year-end 2019 in part due to a nearly 30 percent reduction in crude oil prices. Additionally, Murphy’s focus on free cash flow generation, resulting in a lower capital allocation and flatter oil shale production over the five-year plan, has led to approximately 149 MMBOE net of Eagle Ford Shale and Kaybob Duvernay proved undeveloped reserves being reclassified as probable reserves.

These proved reserve reductions were partially offset by improved well performance in the Gulf of Mexico totaling 13 MMBOE net, as well as sanctioning the Tupper Montney development, which added more than 750 billion cubic feet equivalent (BCFE), or 126 MMBOE, of proved reserves with low subsurface risk.

The company maintained a reserve life index in excess of 11 years with 57 percent proved developed reserves.

“We are pleased with the improved well performance in our Gulf of Mexico wells. Further, by sanctioning the low-cost Tupper Montney development, we were able to add more than 750 BCFE of, natural gas reserves with minimal subsurface risk to our proved reserve base,” stated Jenkins. “Outside of the current five-year plan, we do plan to continue developing the Eagle Ford Shale and Kaybob Duvernay, which would lead to the probable reserves being reclassified as proved undeveloped reserves.”

REGIONAL OPERATIONS SUMMARY

North American Onshore

The North American onshore business produced approximately 82 MBOEPD in the fourth quarter.

Eagle Ford Shale – During the quarter, production averaged 31 MBOEPD with 71 percent oil volumes.

Tupper Montney – Natural gas production averaged 234 million cubic feet per day (MMCFPD) for the quarter.

Kaybob Duvernay – Fourth quarter production averaged 10 MBOEPD.

Global Offshore

The offshore business produced 67 MBOEPD for the fourth quarter, comprised of 79 percent oil. This excludes production from discontinued operations and noncontrolling interest. Gulf of Mexico production in the quarter averaged 63 MBOEPD, consisting of 78 percent oil. Canada offshore production averaged 4 MBOEPD, comprised of 100 percent oil.

Gulf of Mexico – The company progressed the Calliope project subsea work during the quarter and remains on schedule for second quarter 2021 production. The Khaleesi, Mormont and Samurai project advanced ahead of the 2021 drilling campaign, with first oil remaining on target for mid-2022. Construction of the King’s Quay floating production system continued and is approximately 90 percent complete, having reached a significant milestone of mating the hull and topsides.

Murphy, along with its operating partner, drilled a producer well and injector well for the St. Malo waterflood during the quarter. The company also worked with a separate operating partner to spud the Lucius #9 and Lucius #3 wells in Keathley Canyon. Completions work was initiated on the non-operated Kodiak #3 well, which is scheduled to come online in first quarter 2021.

EXPLORATION

Gulf of Mexico – The non-operated Highgarden well (Green Canyon 895) reached total depth in the fourth quarter and has been classified as a dry hole. The 20 percent working interest resulted in a final cost of $12.8 million net to Murphy.

Also in the fourth quarter, Murphy successfully bid on eight blocks in the deepwater Gulf of Mexico lease sale with a net cost of $5.3 million for 100 percent working interest. These blocks include five prospects and provide standalone and near-field opportunities with an average gross resource potential of more than 90 MMBOE. Subsequent to quarter end, these blocks were awarded to Murphy by the Bureau of Energy Management.

Murphy has farmed into an attractive play-opening trend with Chevron as operator, and the first well is planned for the Silverback prospect (Mississippi Canyon 35). The acreage is located adjacent to a large position held by Murphy and its partners.

2021 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE

Murphy is planning 2021 capital expenditures (CAPEX) to be in the range of $675 to $725 million with full year 2021 production to be in the range of 155 to 165 MBOEPD, comprised of approximately 52 percent oil and 59 percent total liquids volumes. Production for first quarter 2021 is estimated to be in the range of 149 to 157 MBOEPD. Both production and CAPEX guidance ranges exclude Gulf of Mexico noncontrolling interest (NCI). Murphy’s 2021 plan reflects management’s continued focus on spending within cash flow, with capital directed toward major projects and short-term free cash flow-generating projects. Such a plan would allow the company to return cash to shareholders through the longstanding dividend, with additional cash utilized in a price recovery to pay down debt.

The table below illustrates the capital allocation by area.

For 2021, Murphy has allocated approximately $325 million, or 46 percent, of capital to the Gulf of Mexico for both development drilling and field development projects. These projects include activities related to the previously sanctioned Khaleesi / Mormont and Samurai developments, and the St. Malo waterflood project. The non-operated Kodiak #3 well (Mississippi Canyon 727), Lucius #9 well (Keathley Canyon 919), Lucius #3 well (Keathley Canyon 918) are scheduled to be complete and placed online in the first half of 2021.

Canada offshore spending comprises 1 percent of the budget, with approximately $5 million earmarked to support Hibernia.

The company forecasts total 2021 offshore production volumes to average 72 MBOEPD, with Gulf of Mexico production of 68 MBOEPD. Canada offshore production is forecast at 4 MBOEPD, noting that non-operated Terra Nova continues to remain offline for repairs.

Murphy plans to spend $170 million in the Eagle Ford Shale, which is 17 percent lower than in 2020. This capital includes $115 million for drilling and bringing online 19 operated wells in the company’s Karnes and Catarina acreage, as well as drilling 2 and bringing online 53 non-operated wells during the year, primarily in Karnes. Murphy’s Eagle Ford Shale budget also includes $55 million for field development.

The company has also allocated $95 million to its Canada onshore business in the Kaybob Duvernay, Tupper Montney and Placid Montney. Approximately $85 million is allocated to the newly sanctioned Tupper Montney development to drill 10 operated wells and bring online 14 operated wells. The remaining amount is primarily allocated to Kaybob Duvernay for field development.

Note: All well counts are shown gross. Eagle Ford Shale non-operated working interest averages 18 percent.

North American onshore production for 2021 is forecast to remain flat at approximately 87 MBOEPD. Annual average production in the Eagle Ford Shale is expected at approximately 30 MBOEPD, while the Kaybob Duvernay is planned to produce 7 MBOEPD. Non-operated Placid Montney production is projected to remain flat at nearly 2 MBOEPD. Tupper Montney production is forecast to increase to approximately 288 MMCFD (48 MBOEPD).

Approximately $75 million is allocated to the 2021 exploration program in the Gulf of Mexico, offshore Mexico and Brazil, with the majority of spending allocated to drilling. Other capital of approximately $30 million, or 4 percent of budget, primarily consists of capitalized interest.

Detailed guidance for the first quarter and full year 2021 is contained in the following schedule.

“Our major Gulf of Mexico projects continue to move forward, with the drilling campaign for Khaleesi, Mormont and Samurai launching early this year, along with drilling meaningful exploration wells in Brazil and Gulf of Mexico,” stated Jenkins. “Further, I am pleased with sanctioning the low cost, capital efficient Tupper Montney development. Over the past few years, we have seen great improvement in all facets of these operations, including reductions in operating expenses and drilling and completions costs, as well as stronger base production performance. When coupled with the macro improvements of higher Canadian natural gas prices and production debottlenecking in the area, the Tupper Montney now competes with premiere shale assets in North America.”

CONFERENCE CALL AND WEBCAST SCHEDULED FOR JANUARY 28, 2021

Murphy will host a conference call to discuss fourth quarter 2020 financial and operating results on Thursday, January 28, 2021, at 9:00 a.m. ET. The call can be accessed either via the Internet through the Investor Relations section of Murphy Oil’s website at http://ir.murphyoilcorp.com or via the telephone by dialing toll free 1-888-886-7786, reservation number 95330576.

FINANCIAL DATA

Summary financial data and operating statistics for fourth quarter 2020, with comparisons to the same period from the previous year, are contained in the following schedules. Additionally, a schedule indicating the impacts of items affecting comparability of results between periods, a reconciliation of EBITDA and EBITDAX between periods, as well as guidance for the first quarter and full year 2021, are also included.

¹In accordance with GAAP, Murphy reports the 100 percent interest, including a 20 percent noncontrolling interest (NCI), in its subsidiary, MP Gulf of Mexico, LLC (MP GOM). The GAAP financials include the NCI portion of revenue, costs, assets and liabilities and cash flows. Unless otherwise noted, the financial and operating highlights and metrics discussed in this news release, but not the accompanying schedules, exclude the NCI, thereby representing only the amounts attributable to Murphy.

ABOUT MURPHY OIL CORPORATION

As an independent oil and natural gas exploration and production company, Murphy Oil Corporation believes in providing energy that empowers people by doing right always, staying with it and thinking beyond possible. Murphy challenges the norm, taps into its strong legacy and uses its foresight and financial discipline to deliver inspired energy solutions. The company sees a future where it is an industry leader who is positively impacting lives for the next 100 years and beyond. Additional information can be found on the company’s website at www.murphyoilcorp.com.

FORWARD-LOOKING STATEMENTS

This news release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”) and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.

NON-GAAP FINANCIAL MEASURES

This news release contains certain non-GAAP financial measures that management believes are useful tools for internal use and the investment community in evaluating Murphy Oil Corporation’s overall financial performance. These non-GAAP financial measures are broadly used to value and compare companies in the crude oil and natural gas industry. Not all companies define these measures in the same way. In addition, these non-GAAP financial measures are not a substitute for financial measures prepared in accordance with GAAP and should therefore be considered only as supplemental to such GAAP financial measures. Please see the attached schedules for reconciliations of the differences between the non-GAAP financial measures used in this news release and the most directly comparable GAAP financial measures.

RESERVE REPORTING TO THE SECURITIES EXCHANGE COMMISSION

The SEC requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We may use certain terms in this news release, such as “resource”, “gross resource”, “recoverable resource”, “net risked P_MEAN resource”, “recoverable oil”, “resource base”, “EUR” or “estimated ultimate recovery” and similar terms that the SEC’s rules prohibit us from including in filings with the SEC. The SEC permits the optional disclosure of probable and possible reserves; however, we have not disclosed the company’s probable and possible reserves in our filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent Annual Report on Form 10-K filed with the SEC and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com.

Kelly Whitley, This email address is being protected from spambots. You need JavaScript enabled to view it., 281-675-9107
Megan Larson, This email address is being protected from spambots. You need JavaScript enabled to view it., 281-675-9470

Technology interoperability broadens EV charging intelligence and control for utilities with AI-based analytics, optimization and command of real-time operating data

REDWOOD CITY, Calif. & QUEBEC CITY--(BUSINESS WIRE)--AutoGrid, the market leader in AI-powered flexibility management software for the energy industry, today announced technological compatibility with the FLO® and AddEnergie® group , a leading operator of the FLO electric vehicle (EV) charging network and provider of smart charging software and equipment, to provide AutoGrid Flex™ for utility management of smart charging endpoints.

The collaboration elevates utilities’ capacity for the continuous measurement, monitoring and control of EV charging at scale. With AutoGrid Flex’s AI-based analytics and real-time operating data in place, utilities can obtain endpoint-level and network-wide visibility and intelligence on participating AddEnergie-manufactured smart charging stations deployed on the FLO network within their service territories. This provides the ability to manage loads for peak demand shaving, enhance the stability of EV charging loads, and improve grid reliability according to the overall impact of charging network activity.

Transportation electrification is steadily accelerating as EVs are projected to account for 28% of global new car sales by 2030 and 58% by 2040. More utilities are recognizing and acting on the necessity of including EV charger data within the calculus of real-time load management and leveraging AI-enabled tools to enhance grid flexibility while enabling the influx of EVs onto the grid.

AutoGrid Flex is being actively used for management of AddEnergie-operated residential EV charging infrastructure installed within a major West Coast utility’s service territory. The best practices and lessons derived from the work with this utility and other organizations in North America are being applied to a wider range of residential and commercial fleet use cases.

“With the number of EVs on the road expected to skyrocket over the coming decades, management of vehicle charging is an imperative new area of Smart Grid proficiency for utilities at the distribution level,” said Frank Fata, Global Head, Utilities at FLO | AddEnergie. “In AutoGrid we’ve found a company with a deep understanding of what is required to integrate and leverage real-time edge intel gathered from smart FLO EV chargers. This datastream will empower utility operations to achieve greater reliability, visibility and operability of these dynamic endpoints which elevates both uptime and customer experience.”

“This work with FLO | AddEnergie, an established player in EV charging, speaks to an increasingly important aspect of our mission to create a more flexible, responsive electrical grid,” said Paul Schinke, senior manager of customer success at AutoGrid. “Vehicle electrification will exert more influence on the overall shape of energy demand year after year. We are strengthening the foundation for successful management of these changes through these new ties to FLO | AddEnergie.”

About AutoGrid:

AutoGrid builds AI-powered software solutions that enable a smarter energy world. The company’s suite of flexibility management applications allows utilities, electricity retailers, renewable energy project developers and energy service providers to deliver clean, affordable and reliable energy by managing networked distributed energy resources (DERs) in real time, at scale through different value streams. AutoGrid’s flagship application, AutoGrid Flex, is ranked as the #1 Virtual Power Plant Platform in the world according to the global ranking published in 2020 by industry-leading research and analysis firm Guidehouse (formerly, Navigant Research).

About FLO | AddEnergie

AddEnergie is a leading North American charging network operator for electric vehicles and a major provider of smart charging software and equipment. Every month, AddEnergie charging stations and its FLO network enable approximately half a million charging events and the transfer of 5.5 GWh in electricity, thanks to over 35,000 high-quality stations deployed on public networks, commercial and residential installations. AddEnergie’s headquarters and network operations centre are based in Quebec City, and its assembly plant is located in Shawinigan (Quebec). The company also has an office in Montreal and regional teams located in Ontario, British Columbia, California, New York and Florida.

AutoGrid
Leo Traub
Antenna Group for AutoGrid
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FLO | AddEnergie
Sylvain Bouffard
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• 2020 earnings per share were $2.79 compared with $2.64 per share in 2019.

• Xcel Energy reaffirms 2021 EPS earnings guidance of $2.90 to $3.00 per share.

MINNEAPOLIS--(BUSINESS WIRE)--Xcel Energy Inc. (NASDAQ: XEL) today reported 2020 GAAP and ongoing earnings of $1.47 billion, or $2.79 per share, compared with $1.37 billion, or $2.64 per share in the same period in 2019.

“Xcel Energy had a strong year despite the challenges brought on by COVID-19,” said Ben Fowke, chairman and CEO. “We achieved major milestones while keeping our employees and customers safe and are well positioned for the coming year and beyond.”

“I’m proud of the support we provided our communities, committing nearly $20 million to short and long-term corporate giving. Our $750 million plan to repower several wind farms in Minnesota was approved, which is expected to result in substantial customer savings and jobs creation. In Colorado, we received approval for an electric vehicle plan and are excited about the related opportunities. We also announced the early retirement of the Hayden and Craig coal plants and plans to convert our Harrington facility to natural gas. These achievements move us closer to achieving our goals of an 80% carbon reduction by 2030 and delivering 100% carbon-free electricity by 2050.”

At 9:00 a.m. CDT today, Xcel Energy will host a conference call to review financial results. To participate in the call, please dial in 5 to 10 minutes prior to the start and follow the operator’s instructions.

The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website at www.xcelenergy.com. To access the presentation, click on Investor Relations. If you are unable to participate in the live event, the call will be available for replay from 12:00 p.m. CDT on Jan. 28 through 12:00 p.m. CDT on Jan. 31.

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the 2021 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future bad debt expense, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, and expectations regarding regulatory proceedings, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2019 and subsequent filings with the Securities and Exchange Commission, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs, changes in regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.

This information is not given in connection with any sale, offer for sale or offer to buy any security.

XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor Relations Earnings Release (Unaudited)

Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with generally accepted accounting principles (GAAP), as well as certain non-GAAP financial measures such as ongoing return on equity (ROE), electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Ongoing ROE

Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity.

Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales - other, operating and maintenance (O&M) expenses, conservation and demand side management (DSM) expenses, depreciation and amortization and taxes (other than income taxes).

Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)

GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.

We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the three and twelve months ended Dec. 31, 2020 and 2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.

Note 1. Earnings Per Share Summary

Xcel Energy’s 2020 earnings were $2.79 per share compared to $2.64 per share in 2019, primarily reflecting higher electric margin (largely due to regulatory outcomes which recover capital investment), higher allowance for funds used during construction (AFUDC) and lower O&M expenses, which offset increased depreciation, interest expense and declining sales primarily due to the impacts of COVID-19.

Summarized diluted EPS for Xcel Energy:

^(a) Amounts may not add due to rounding.

NSP-Minnesota — Earnings increased $0.08 per share for 2020, reflecting higher electric margin (riders, wholesale transmission revenue and a sales true-up mechanism, which recovers lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin.

PSCo — Earnings were flat for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and higher natural gas margin, offset by additional depreciation and taxes (other than income taxes).

SPS — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes).

NSP-Wisconsin — Earnings increased $0.05 per share for 2020, reflecting higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin.

Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company.

Components significantly contributing to changes in 2020 EPS compared with 2019:

^(a) Change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 and is detailed below. Sales decline excludes weather impact, net of decoupling/sales true-up and reduction in demand revenue is net of sales true-up.

^(b) Includes production tax credits (PTCs) and tax reform regulatory amounts, which are primarily offset in electric margin.

ROE for Xcel Energy and its utility subsidiaries:

Note 2. Regulated Utility Results

Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance to the extent there is not a decoupling or sales true-up mechanism in the state.

Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. Cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.

Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.

Percentage (decrease) increase in normal and actual HDD, CDD and THI:

Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:

Sales — Sales growth (decline) for actual and weather-normalized sales in 2020 compared to 2019:

^(a) Higher residential sales and lower commercial and industrial (C&I) sales were primarily attributable to COVID-19. The increase in residential sales was partially driven by more customers working from home.

Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day)

• PSCo — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the manufacturing and service industries, partially offset by an increase in the energy sector.

• NSP-Minnesota — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy, manufacturing and services sectors.
• SPS — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors.

• NSP-Wisconsin — Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors.

Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day)

• Higher natural gas sales reflect an increase in the number of customers combined with higher residential customer use, partially offset by lower C&I customer use.

Electric Margin — Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense).

Electric revenues and margin:

Change in electric margin:

^(a) Includes approximately $70 million of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs.

^(b) Sales excludes weather impact, net of decoupling/sales true-up, and demand revenue is net of sales true-up.

Natural Gas Margin — Natural gas expense varies with changing sales and cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on margin due to cost recovery mechanisms.

Natural gas revenues and margin:

Change in natural gas margin:

Paul Johnson, Vice President, Investor Relations, (612) 215-4535

For news media inquiries only, please call Xcel Energy Media Relations, (612) 215-5300

Xcel Energy website address: www.xcelenergy.com

ATHENS, Greece--(BUSINESS WIRE)--Danaos Corporation (the “Company”) (NYSE: DAC) announced today that it plans to commence an offering of up to $300 million of senior unsecured notes due 2028, subject to market conditions and other factors. The notes are to be offered and sold in a private offering exempt from the registration requirements under the U.S. Securities Act of 1933, as amended (the "Securities Act"). The Company intends to use the net proceeds from the offering, together with a new $815 million senior secured credit facility and a new $135 million sale leaseback arrangement, to implement a $1.25 billion refinancing of a substantial majority of its outstanding senior secured indebtedness.

This announcement is not an offer for sale or a recommendation or solicitation to buy or sell any securities, nor shall there be any offer, solicitation, or sale of any securities in any jurisdiction in which such offer, solicitation, or sale would be unlawful. The notes will not be registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements of the Securities Act and applicable state securities laws.

About Danaos Corporation

Danaos Corporation is one of the largest independent owners of modern, large-size containerships. Our current fleet of 65 containerships aggregating 403,793 TEUs, including five vessels owned by Gemini Shipholdings Corporation, a joint venture, ranks Danaos among the largest containership charter owners in the world based on total TEU capacity. Our fleet is chartered to many of the world’s largest liner companies on fixed-rate charters. Danaos Corporation’s shares trade on the New York Stock Exchange under the symbol “DAC”.

Forward-Looking Statements

Matters discussed in this release may constitute forward-looking statements within the meaning of the safe harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements reflect the current views of Danaos Corporation (including subsidiaries unless indicated or the context requires otherwise, the “Company,” “we,” “us,” and “our”) with respect to future events and financial performance and may include statements concerning our operations, cash flows, financial position, including with respect to vessel and other asset values, plans, objectives, goals, strategies, future events, performance or business prospects, changes and trends in our business and the markets in which we operate, and underlying assumptions and other statements, which are other than statements of historical facts. The forward-looking statements in this release are based upon various assumptions. Although we believe that these assumptions were reasonable when made, because these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control, we cannot assure you that we will achieve or accomplish these expectations, beliefs or projections. Important factors that, in our view, could cause actual results to differ materially from those discussed in the forward-looking statements include the impact of the novel coronavirus 2019 (“COVID-19”) pandemic and efforts throughout the world to contain its spread, including effects on global economic activity, demand for seaborne transportation of containerized cargo, the ability and willingness of charterers to fulfill their obligations to us, charter rates for containerships, shipyards performing scrubber installations, drydocking and repairs, changing vessel crews and availability of financing, the effects of the refinancing transactions in 2018, the effects of the contemplated upcoming refinancing transactions, the Company’s ability to achieve the expected benefits of its refinancing transactions and comply with the terms of its credit facilities and other agreements entered into in connection with the such refinancings, the strength of world economies and currencies, general market conditions, including changes in charter hire rates and vessel values, charter counterparty performance, changes in demand that may affect attitudes of time charterers to scheduled and unscheduled drydocking, changes in our operating expenses, including bunker prices, dry-docking and insurance costs, ability to obtain financing and comply with covenants in our financing arrangements, actions taken by regulatory authorities, potential liability from pending or future litigation, domestic and international political conditions, potential disruption of shipping routes due to accidents and political events or acts by terrorists.

Risks and uncertainties are further described in reports filed by Danaos Corporation with the U.S. Securities and Exchange Commission.

The forward-looking statements and information contained in this announcement are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Evangelos Chatzis
Chief Financial Officer
Danaos Corporation
Athens, Greece
Tel.: +30 210 419 6480
E-Mail: This email address is being protected from spambots. You need JavaScript enabled to view it.

Iraklis Prokopakis
Senior Vice President and Chief Operating Officer
Danaos Corporation
Athens, Greece
Tel.: +30 210 419 6400
E-Mail: This email address is being protected from spambots. You need JavaScript enabled to view it.

Investor Relations and Financial Media

Rose & Company
New York
Tel. 212-359-2228
E-Mail: This email address is being protected from spambots. You need JavaScript enabled to view it.

Third Quarter Highlights:

• Subscription revenues of $29.1 million
• Net subscriber base of over 749,000 subscribers
• Net income of $5.9 million
• Adjusted EBITDA of $9.5 million, at a 28.0% margin
• Net cash provided by operating activities of $10.2 million leading to positive free cash flow of $8.7 million
• Cash and cash equivalents of $44.0 million at quarter end

MIDRAND, South Africa & BOCA RATON, Fla.--(BUSINESS WIRE)--MiX Telematics Limited (“MiX Telematics”) (NYSE: MIXT, JSE: MIX), a leading global provider of fleet and mobile asset management solutions delivered as Software-as-a-Service (“SaaS”), today announced financial results, in accordance with accounting principles generally accepted in the United States (“GAAP”), for the third quarter, which ended December 31, 2020.

“MiX Telematics reported third quarter results highlighted by sequential growth in subscription revenue and very strong profitability and free cash flow. We saw modestly improved performance in our premium and light fleet segments for the second straight quarter even as we continue to manage through the impact of COVID-19 on certain key vertical markets," said Stefan Joselowitz, Chief Executive Officer of MiX Telematics.

Joselowitz continued, “As we look ahead, we are very encouraged by the strategic conversations we are having with large fleet operators on the greater role telematics will play in their future operations. This gives us confidence MiX is well positioned to return to attractive subscription revenue growth rates once the economy normalizes.”

Financial Results for the Three Months Ended December 31, 2020

Subscription Revenues: Subscription revenues were $29.1 million, a decrease of 10.2% compared to $32.4 million for the third quarter of fiscal 2020. Subscription revenues represented 85.2% of total revenues during the third quarter of fiscal 2021. Subscription revenues decreased by 7.3% on a constant currency basis, year over year. The decline in constant currency subscription revenue was primarily due to the contraction in the Company’s subscriber base as a result of economic conditions attributable to the COVID-19 pandemic. During the third quarter of fiscal 2021, the Company’s subscriber base contracted by a net 18,300 subscribers. The contraction is primarily attributable to our low ARPU asset tracking subscribers.

The majority of our revenues and subscription revenues are derived from currencies other than the U.S. Dollar. Accordingly, the strengthening of the U.S. Dollar against these currencies (in particular against the South African Rand) following currency volatility arising from the economic disruption caused by COVID-19, has negatively impacted our revenue and subscription revenues reported in U.S. Dollars. Compared to the third quarter of fiscal year 2020, the South African Rand weakened by 6% against the U.S. Dollar. The Rand/U.S. Dollar exchange rate averaged R15.65 in the third quarter of fiscal year 2021 compared to an average of R14.71 during the third quarter of fiscal year 2020. The impact of translating foreign currencies to U.S. Dollars at the average exchange rates during the third quarter of fiscal 2021 led to a 2.9% reduction in reported U.S. Dollar subscription revenues.

Total Revenues: Total revenues were $34.1 million, a decrease of 6.5% compared to $36.5 million for the third quarter of fiscal 2020. Total revenues decreased by 3.6% on a constant currency basis, year over year. Hardware and other revenues were $5.0 million, an increase of 22.5%, compared to $4.1 million for the third quarter of fiscal 2020.

The impact of translating foreign currencies to U.S. Dollars at the average exchange rates during the third quarter of fiscal 2021 led to a 2.9% reduction in reported U.S. Dollar revenues.

Gross Margin: Gross profit was $21.3 million, compared to $23.5 million for the third quarter of fiscal 2020. Gross profit margin was 62.5%, compared to 64.6% for the third quarter of fiscal 2020.

Income From Operations: Income from operations was $5.0 million, compared to $5.2 million for the third quarter of fiscal 2020. Operating income margin was 14.8%, compared to 14.2% for the third quarter of fiscal 2020. Operating expenses of $16.3 million decreased by $2.1 million, or 11.5%, compared to the third quarter of fiscal 2020.

Net Income and Earnings Per Share: Net income was $5.9 million, compared to net income of $5.1 million in the third quarter of fiscal 2020. Net income included a net foreign exchange loss of $0.1 million before tax, as well as a $2.7 million deferred tax credit on a U.S. Dollar intercompany loan between MiX Telematics and MiX Telematics Investments Proprietary Limited (“MiX Investments”), a wholly-owned subsidiary of the Company. During the third quarter of fiscal 2020, net income included a net foreign exchange loss of $0.2 million and a $1.5 million deferred tax credit on a U.S. Dollar intercompany loan between MiX Telematics and MiX Investments.

Earnings per diluted ordinary share was 1.1 U.S. cents, compared to 0.9 U.S. cents in the third quarter of fiscal 2020. For the third quarter of fiscal 2021, the calculation was based on diluted weighted average ordinary shares in issue of 559.8 million compared to 562.4 million diluted weighted average ordinary shares in issue during the third quarter of fiscal 2020. On a ratio of 25 ordinary shares to one American Depositary Share (“ADS”), earnings per diluted ADS was 26 U.S. cents compared to 23 U.S. cents in the third quarter of fiscal 2020.

The Company’s effective tax rate was negative 18.7%, compared to negative 2.4% in the third quarter of fiscal 2020. Ignoring the impact of net foreign exchange losses net of tax, the tax rate used in determining non-GAAP net income below was 34.3% compared to 25.9% in the third quarter of fiscal 2020.

Adjusted EBITDA: Adjusted EBITDA, a non-GAAP measure, was $9.5 million, compared to $10.1 million for the third quarter of fiscal 2020. Adjusted EBITDA margin, a non-GAAP measure, for the third quarter of fiscal 2021 was 28.0%, compared to 27.8% for the third quarter of fiscal 2020.

Non-GAAP Net Income and Non-GAAP Net Income Per Share: Non-GAAP net income was $3.4 million, compared to $3.8 million for the third quarter of fiscal 2020. Non-GAAP net income per diluted ordinary share was 0.6 U.S. cents, compared to 0.7 U.S. cents in the third quarter of fiscal 2020. At a ratio of 25 ordinary shares to one ADS, the non-GAAP net income per diluted ADS was 15 U.S. cents compared to 17 U.S. cents in the third quarter of fiscal 2020.

Cash and Cash Equivalents and Cash Flow: At December 31, 2020, the Company had $44.0 million of cash and cash equivalents, compared to $18.0 million at March 31, 2020.

Net cash provided by operating activities for the three months ended December 31, 2020 was $10.2 million compared to $7.3 million for the three months ended December 31, 2019. The Company invested $1.5 million in capital expenditures (including investments in in-vehicle devices of $0.4 million), leading to free cash flow, a non-GAAP measure, of $8.7 million in the quarter. The Company generated free cash flow of $1.3 million for the third quarter of fiscal 2020 when the Company invested $6.0 million in capital expenditures (including investments in in-vehicle devices of $4.5 million).

Net cash utilized by financing activities amounted to $1.7 million for the third quarter of fiscal 2021, compared to $0.2 million utilized during the third quarter of fiscal 2020. The cash utilized by financing activities during the third quarter of fiscal 2021 consisted of dividends paid of $1.4 million and $0.3 million from a reduction in facilities utilized. The cash utilized in financing activities during the third quarter of fiscal 2020 consisted of dividends paid of $1.5 million offset by facilities utilized of $1.3 million.

During the quarter, the South African Rand strengthened against the U.S. Dollar from R17.00 at September 30, 2020 to R14.65 at December 31, 2020 and as a result, cash increased by $3.1 million due to foreign exchange gains.

Quarterly Dividend

The most recent dividend payment of 4 South African cents (0.3 U.S. cents) per ordinary share and 1 South African Rand (7 U.S. cents) per ADS was paid on November 23, 2020 to shareholders on record on November 20, 2020. A dividend of 4 South African cents per ordinary share and 1 South African Rand per ADS will be paid on March 9, 2021 to shareholders on record as of the close of business on February 19, 2021.

The details with respect to the dividends declared for holders of our ADSs are as follows:

Share Repurchases

No shares were repurchased during the three months ended December 31, 2020.

Business Outlook

Due to the uncertainty surrounding the level of business disruption as a result of the spread of COVID-19, the Company has suspended its practice of issuing financial guidance and as a consequence no guidance has been issued for the full 2021 fiscal year.

Conference Call Information

MiX Telematics management will host a conference call and audio webcast at 8:00 a.m. (Eastern Daylight Time) and 3:00 p.m. (South African Time) on Thursday, January 28, 2021 to discuss the Company’s financial results and current business outlook:

• The live webcast of the call will be available at the “Investor Information” page of the Company’s website, http://investor.mixtelematics.com.
• To access the call, dial +1-877-451-6152 (within the United States) or 0 800 983 831 (within South Africa) or +1-201-389-0879 (outside of the United States). The conference ID is 13715107.
• A replay of this conference call will be available for a limited time at +1-844-512-2921 (within the United States) or +1-412-317-6671 (within South Africa or outside of the United States). The replay conference ID is 13715107.
• A replay of the webcast will also be available for a limited time at http://investor.mixtelematics.com.

About MiX Telematics Limited

MiX Telematics is a leading global provider of fleet and mobile asset management solutions delivered as SaaS to customers managing over 749,000 assets in approximately 120 countries. The Company’s products and services provide enterprise fleets, small fleets and consumers with solutions for safety, efficiency, risk and security. MiX Telematics was founded in 1996 and has offices in South Africa, the United Kingdom, the United States, Uganda, Brazil, Australia, Romania, Thailand and the United Arab Emirates as well as a network of more than 130 fleet partners worldwide. MiX Telematics shares are publicly traded on the Johannesburg Stock Exchange (JSE: MIX) and MiX Telematics American Depositary Shares are listed on the New York Stock Exchange (NYSE: MIXT). For more information visit www.mixtelematics.com.

Forward-Looking Statements

This press release includes certain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, including without limitation, statements regarding our position to execute on our growth strategy, and our ability to expand our leadership position. These forward-looking statements include, but are not limited to, Company’s beliefs, plans, goals, objectives, expectations, assumptions, estimates, intentions, future performance, other statements that are not historical facts and statements identified by words such as “expects”, “anticipates”, “intends”, “plans”, “believes”, “seeks”, “estimates” or words of similar meaning. These forward-looking statements reflect our current views about our plans, intentions, expectations, strategies and prospects, which are based on the information currently available to us and on assumptions we have made. Although we believe that our plans, intentions, expectations, strategies and prospects as reflected in, or suggested by, these forward-looking statements are reasonable, we can give no assurance that the plans, intentions, expectations or strategies will be attained or achieved.

Furthermore, actual results may differ materially from those described in the forward-looking statements and will be affected by a variety of known and unknown risks and uncertainties, some of which are beyond our control including, without limitation:

• the severity and duration of the COVID-19 pandemic, the pandemic’s economic impact on the geographical locations of our regional service organizations and central service organization, the impact of the pandemic on our customers’ ability to meet their financial obligations, our ability to implement cost containment and business recovery strategies during the pandemic, local and foreign government regulations implemented to combat the pandemic and any future developments on the pandemic;
• our ability to attract, sell to and retain customers;
• our ability to improve our growth strategies successfully, including our ability to increase sales to existing customers;
• our ability to adapt to rapid technological change in our industry;
• competition from industry consolidation;
• loss of key personnel or our failure to attract, train and retain other highly qualified personnel;
• our ability to integrate any businesses we acquire;
• the introduction of new solutions and international expansion;
• our dependence on key suppliers and vendors to manufacture our hardware;
• our dependence on our network of dealers and distributors to sell our solutions;
• businesses may not continue to adopt fleet management solutions;
• our future business and system development, results of operations and financial condition;
• expected changes in our profitability and certain cost or expense items as a percentage of our revenue;
• changes in the practices of insurance companies;
• the impact of laws and regulations relating to the Internet and data privacy;
• our ability to protect our intellectual property and proprietary technologies and address any infringement claims;
• our ability to defend ourselves from litigation or administrative proceedings relating to labor, regulatory, tax or similar issues;
• significant disruption in service on, or security breaches of, our websites or computer systems;
• our dependence on third-party technology;
• fluctuations in the value of the South African Rand;
• economic, social, political, labor and other conditions and developments in South Africa and globally;
• our ability to issue securities and access the capital markets in the future; and
• other risks set forth in our filings with the U.S. Securities Exchange Commission.

We assume no obligation to update any forward-looking statements contained in this press release and expressly disclaim any obligation to do so, whether as a result of new information, future events or otherwise, except as required by law.

Use of Non-GAAP Financial Measures

This press release and the accompanying tables include references to Adjusted EBITDA, Adjusted EBITDA margin, non-GAAP net income and non-GAAP net income per share, free cash flow and constant currency, which are non-GAAP financial measures. For a description of these non-GAAP financial measures, including the reasons management uses these measures, please see Annexure A titled “Non-GAAP Financial Measures”. A reconciliation of these non-GAAP financial measures to the most directly comparable financial measures prepared in accordance with GAAP is provided in Annexure A.