The Port’s Future is Bright

HOUSTON--(BUSINESS WIRE)--The Port Commission of the Port of Houston Authority held its first meeting of the year on Tuesday.

Port Chairman Ric Campo began the meeting by expressing his appreciation for the efforts of Houston Ship Channel partners, including federal officials and industry stakeholders and Port Authority staff, as Project 11 (the Houston Ship Channel Improvement program) achieved two significant milestones.

Earlier this month, Project 11 received a “new start” designation, and $19.5 million in federal funds were included in the U.S. Army Corps of Engineers 2021 work program to support its work to widen and deepen the channel. This followed authorization of Project 11 in the Water Resources and Development Act of 2020, as part of a larger legislative package passed by Congress in December.

“The significance of this appropriation is tremendous, as it paves the way to a clearer and smoother path to the start of construction,” Chairman Campo said. He underlined the importance of the designation, adding that “there is only one new start designation for a major deep-water channel in the U.S. each year.”

Chairman Campo emphasized that channel partners “were essential in pushing this decision over the top in the 11th hour.” Chairman Campo also laid out key priorities to keep Project 11 moving forward to be “turning dirt” later this year.

Executive Director Roger Guenther highlighted achievements and accomplishments made in 2020 in his staff report to the Commission.

He said that despite the challenges due to the pandemic, Port Houston handled 2.99 million twenty-foot equivalent container units (TEU) in 2020. This mark fell “just shy” of last year’s record by only 828 TEU. Guenther described that as “about a half-day’s work on one ship with three gangs (work crews) working.”

In his report, Guenther also said that there is a bright future for the port that “can only get better” saying that the public container terminals have taken off with a rapid start in 2021. He showcased an aerial photo of the first ship to use six cranes that boasted the second-largest lift count (cranes moving containers from ships) on a vessel operation at Port Houston’s public facilities.

Guenther said that this activity demonstrates the “pent-up demand” by carriers to bring larger vessels to the port, and the urgency to complete Project 11.

The staff briefing included an update and discussion on the Port Authority’s recent draft Disparity Study and Small Business Development Program. Port Authority staff has been “working diligently” on developing recommendations “for a race- and gender- conscious supplier diversity program for Port Commission consideration.”

Chairman Campo said, “Initial discussions will take place with the Commission’s Procurement and Small Business Task Force, to develop elements of a MWBE program to enhance the Port Authority’s Small Business program.”

He described the process to include creating policy, identifying resources, developing a budget, and defining program activities, with an advisory and peer review.

Chairman Campo said, “We will push forward to identify steps to successful preparation and implementation of this program.”

Port Houston has also released its Clean Air Strategy Plan draft: https://porthouston.com/environment/air-quality/.

The Clean Air Strategy Plan Draft will be available for public comment until Feb. 24. The public may email comments to: This email address is being protected from spambots. You need JavaScript enabled to view it..

The next regular Port Commission meeting is scheduled for Feb. 23.

About Port Houston

For more than 100 years, Port Houston has owned and operated the public wharves and terminals along the Houston Ship Channel, including the area’s largest breakbulk facility and two of the most efficient and fastest-growing container terminals in the country. Port Houston is the advocate and a strategic leader for the Channel. The Houston Ship Channel complex and its more than 200 public and private terminals, collectively known as the Port of Houston, is the nation’s largest port for waterborne tonnage and an essential economic engine for the Houston region, the state of Texas, and the U.S. The Port of Houston supports the creation of nearly 1.35 million jobs in Texas and 3.2 million jobs nationwide, and economic activity totaling $339 billion in Texas – 20.6 percent of Texas’ total gross domestic product (GDP) – and $801.9 billion in economic impact across the nation. For more information, visit the website at www.PortHouston.com.

Lisa Ashley, Director, Media Relations
Office: 713-670-2644; Mobile: 832-247-8179
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• Robust financial position and lower net debt in 2020 thanks to the success of the adaptation and cost reduction plan
  • Cash breakeven before debt servicing lowered below $30/bbl as a result of cost reduction efforts in 2020
  • Net debt of $455 million at 31 December 2020, down from the previous fiscal year ($469 million at 31 December 2019)
  • Cash position of $168 million at 31 December 2020, after debt repayments of $77 million during the year

• M&P working interest in 2020: 26,076 boepd
  • M&P working interest production on the Ezanga permit in Gabon of 16,896 bopd, down 15% from 2019 due to production cuts related to OPEC quotas
  • M&P working interest production of 3,933 bopd in Angola and 31.5 MMcfd in Tanzania

• Sales of $330 million in 2020, down sharply as a result of the drop in crude prices
  • Average sale price of oil $40.1/bbl, down 40% from 2019 ($67.2/bbl)
  • Valued production (income from production activities, excluding lifting imbalances): $324 million, down 37% from 2019 ($519 million)

• 2P reserves for M&P working interest at 31 December 2020: 183 MMboe
  • Reserves stable after being restated for 2020 production

PARIS--(BUSINESS WIRE)--Regulatory News:

Olivier de Langavant, Chief Executive Officer at Maurel & Prom (Paris:MAU), stated:

“In a year marked by a particularly difficult economic environment, Maurel & Prom demonstrated its responsiveness by taking immediate action to address the difficulties encountered. Despite a sharp drop in crude prices and reduced output due to OPEC quotas, we managed to reduce net debt during the year, thereby proving the effectiveness of the action plan introduced in March. We are now looking to keep up these efforts, as well as initiatives enabling us to take advantage of this period to put Maurel & Prom in the best possible position for its long-term development.ˮ

Key indicators for 2020

¹ 4,484 bopd for M&P working interest during the asset-holding period (1 August to 31 December 2019).

M&P’s working interest production for 2020 stood at 26,076 boepd, down 5% from 2019 (27,340 boepd). This decline was largely due to production cuts on the Ezanga permit in Gabon (16,896 bopd for M&P working interest in 2020 versus 19,828 bopd in 2019) after OPEC established new quotas.

The average sale price of oil was $40.1/bbl versus $67.2/bbl in 2019, a drop of 40%.

The Group’s valued production (income from production activities, excluding lifting imbalances) was $324 million, down 37% from 2019. The restatement of lifting imbalances net of inventory revaluation had a neutral effect overall and resulted in a downwards adjustment of $1 million. After inclusion of the $6 million earned from the activities of the drilling subsidiary (Caroil), Group consolidated sales for the year totalled $330 million.

Production activities

• Gabon

M&P’s working interest oil production (80%) on the Ezanga permit was 16,896 bopd (total production: 21,120 bopd) in 2020, down 15% from 2019. The company took advantage of the period of low crude prices to temporarily suspend production at certain wells, starting in May 2020, in order to improve reservoir conditions for the long term. This effort has subsequently continued under the quotas established by OPEC, of which Gabon is a member.

In January 2021, production at the Ezanga field was still limited to 19,000 bopd (or 15,200 bopd for M&P working interest). It is expected that this constraint will be gradually relaxed during the first half of 2021.

• Tanzania

M&P’s working interest gas production (48.06%) on the Mnazi Bay permit stood at 31.5 MMcfd (total production: 65.5 MMcfd) in 2020, a slight drop of 7% compared to 2019.

This decline was offset at the sales level by the allocation of additional rights to M&P. These rights related to corporate income tax now being charged to the partner TPDC, pursuant to the production sharing contract. Consequently, M&P sales in Tanzania rose by 26% to $43 million, versus $34 million in 2019.

• Angola

M&P’s working interest production (20%) in Block 3/05 in 2020 was 3,933 bopd (total production: 19,663 bopd). Despite the drop in crude oil prices, valued production was up by 30% ($40 million versus $31 million in 2019) due to the asset being included over the entire period (versus just five months in 2019).

Group reserves as at 31 December 2020

The Group's reserves correspond to the volumes of technically recoverable hydrocarbons representative of the Group’s share of interests in permits currently in production plus those revealed by discovery and delineation wells that can be operated commercially. These reserves were certified as at 31 December 2020 by DeGolyer and MacNaughton in Gabon, Angola and France, and by RPS Energy in Tanzania.

The Group’s 2P reserves stood at 182.9 MMboe at 31 December 2020, including 120.1 MMboe of proven reserves (1P). The change from 2019 was due to production in the year just ended, with no significant revision in 2020.

2P reserves for M&P working interest:

Note that these figures do not take into account the 20.46% interest held by M&P in Seplat, which is one of Nigeria’s main operators listed on the London and Lagos stock exchanges. For the record, Seplat’s 2P reserves stood at 509 MMboe at 1 January 2020 (or 104 MMboe for the 20.46% stake held by M&P).

In addition, due to the international sanctions against Venezuela’s state oil company PDVSA, the activity of M&P, relating to its stake in the company PRDL, is limited for the time being to operations related solely to the safety of staff and assets, and to environmental protection. Consequently, no reserve to date has been retained as regards this share.

Financial position

The Group’s cash position at 31 December 2020 stood at $168 million, versus $212 million at 30 June 2020 and $231 million at 30 September 2020. Net debt fell in 2020 from $469 million to $455 million after a $77-million debt repayment ($75 million for the Term Loan and $2 million for the Shareholder Loan).

The $43 million debt of the Gabon Oil Company (GOC) associated with its entry on the Ezanga permit in 2019, and corresponding to the amount owed to M&P in respect of the pre-2018 carrying cost, has now been validated through a procedure to obtain an expert opinion from the ICC (International Chamber of Commerce). These $43 million, which are not included in the cash position of $168 million at 31 December 2020, are subject to procedures in order to obtain them quickly.

The cost-cutting initiatives that began in March 2020 and the asset impairments recorded during the first half of 2020 significantly lowered the Group’s breakeven in terms of net income. The breakeven is now $45/bbl (excluding exceptional items and share of Seplat’s earnings) based on current production figures. As far as the cash breakeven is concerned, this is less than $30/bbl before debt servicing.

For more information, visit www.maureletprom.fr

This document may contain forward-looking statements regarding the financial position, results, business and industrial strategy of Maurel & Prom. By nature, forward-looking statements contain risks and uncertainties to the extent that they are based on events or circumstances that may or may not happen in the future. These projections are based on assumptions we believe to be reasonable, but which may prove to be incorrect and which depend on a number of risk factors, such as fluctuations in crude oil prices, changes in exchange rates, uncertainties related to the valuation of our oil reserves, actual rates of oil production and the related costs, operational problems, political stability, legislative or regulatory reforms, or even wars, terrorism and sabotage.

Maurel & Prom is listed for trading on Euronext Paris
CAC All-Tradable – CAC Small – CAC Mid & Small – Eligible PEA-PME and SRD
Isin FR0000051070/Bloomberg MAU.FP/Reuters MAUP.PA

Maurel & Prom
Press, shareholder and investor relations
Tel: +33 (0)1 53 83 16 45
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NewCap
Financial communications and investor relations/Media relations
Louis-Victor Delouvrier/Nicolas Merigeau
Tel: +33 (0)1 44 71 98 53/+33 (0)1 44 71 94 98
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ALEXANDRIA, Va.--(BUSINESS WIRE)--VSE Corporation (NASDAQ: VSEC), a leading provider of aftermarket distribution and maintenance, repair and overhaul (MRO) services for land, sea and air transportation assets in the public and private sectors, today announced it has commenced an underwritten public offering, subject to market and other conditions, of shares of its common stock pursuant to an effective shelf registration statement. In addition, VSE intends to grant the underwriters an option for a period of 30 days to purchase up to an additional 15% of the shares of common stock offered in the public offering.

VSE expects to use the net proceeds from this offering for general corporate purposes, which may include among other things, financing strategic acquisitions, working capital requirements for new program launches, and repaying outstanding borrowings under its revolving credit facility.

William Blair & Company, L.L.C. and Canaccord Genuity LLC are acting as joint book-running managers and representatives of the underwriters for the offering.

A shelf registration statement relating to the securities being offered has been filed with the Securities and Exchange Commission (the “SEC”) and has been declared effective. This press release does not constitute an offer to sell or the solicitation of an offer to buy any securities described herein, nor shall there be any sale of the securities in any state or jurisdiction in which such an offer, solicitation or sale would be unlawful prior to registration or qualification under the securities law of any such jurisdiction. The offering is being made only by means of a preliminary prospectus supplement and accompanying prospectus. A preliminary prospectus supplement and accompanying prospectus relating to the offering have been filed with the SEC and are available free of charge on the SEC’s website at http://www.sec.gov. Copies of the preliminary prospectus supplement and accompanying prospectus relating to this offering of securities may also be obtained from William Blair & Company, L.L.C., Attention: Prospectus Department, 150 North Riverside Plaza, Chicago, Illinois 60606, by telephone at (800) 621-0687 or by email at This email address is being protected from spambots. You need JavaScript enabled to view it. or Canaccord Genuity LLC, 99 High Street, 12th Floor, Boston, MA 02110, Attention: Syndicate Department, or by email at This email address is being protected from spambots. You need JavaScript enabled to view it..

ABOUT VSE CORPORATION

VSE is a leading provider of aftermarket distribution and repair services for land, sea and air transportation assets for government and commercial markets. Core services include maintenance, repair and overhaul (MRO) services, parts distribution, supply chain management and logistics, engineering support, and consulting and training services for global commercial, federal, military and defense customers. VSE also provides information technology and energy consulting services. For additional information regarding VSE’s services and products, visit us at www.vsecorp.com.

FORWARD-LOOKING STATEMENTS

This press release may contain statements that, to the extent they are not recitations of historical fact, constitute "forward looking statements" within the meaning of applicable U.S. federal securities laws. All such statements are intended to be covered by the safe harbor provisions for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995 and includes this statement for purposes of such safe harbor provisions.

“Forward-looking” statements, as such term is defined by the SEC in its rules, regulations and releases, represent our expectations or beliefs, including, but not limited to, statements concerning our operations, economic performance, financial condition, growth and acquisition strategies, investments and future operational plans. Without limiting the generality of the foregoing, words such as “may,” “will,” “expect,” “believe,” “anticipate,” “intend,” “forecast,” “seek,” “plan,” “predict,” “project,” “could,” “estimate,” “might,” “continue,” “seeking” or the negative or other variations thereof or comparable terminology are intended to identify forward-looking statements.

These statements speak only as of the date of this press release and we undertake no ongoing obligation, other than that imposed by law, to update these statements. These statements relate to, among other things, our intent, belief or current expectations with respect to: our future financial condition, results of operations or prospects; our business and growth strategies; and our financing plans and forecasts. You are cautioned that any such forward-looking statements are not guarantees of future performance and involve significant risks and uncertainties, and that actual results may differ materially from those contained in or implied by the forward-looking statements as a result of various factors, some of which are unknown, including, without limitation:

• delays in contract awards and funding due to uncertain government budgets and shifting government priorities;
• the impact on our business, results of operations and financial condition from the ongoing and global COVID-19 pandemic, or any other pandemic, epidemic or outbreak of infectious disease in the United States or globally;
• intense competition from existing and new competitors;
• our ability to renew and/or maintain certain programs that comprise a material portion of our revenue;
• changes in procurement processes and government regulations and our ability to comply with such requirements;
• the performance of the aviation aftermarket, which could be impacted by lower demand for business aviation and commercial air travel or airline fleet changes causing lower demand for our goods and services;
• our ability to successfully execute our acquisition strategy;
• changes in future business conditions, which could negatively impact our business investments, recorded goodwill, and/or purchased intangible assets;
• the adverse impact of government audits or investigations on our business;
• changes in governmental rules and regulations, including with respect to environmental matters, and related costs and liabilities;
• adverse economic conditions in the United States and globally;
• security threats, including cyber security threats, and related disruptions;
• our dependence on access to and performance of third-party package delivery companies;
• our high level of indebtedness;
• our ability to raise capital to fund our operations; and
• the other risk factors mentioned under Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019, our subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2020 and June 30, 2020 and our other filings with the SEC from time to time.

You are advised, however, to consult any further disclosures we make on related subjects in our periodic reports on Forms 10-K, 10-Q or 8-K filed or furnished to the SEC.

INVESTOR RELATIONS CONTACT: Noel Ryan | Phone: 720.778.2415 | This email address is being protected from spambots. You need JavaScript enabled to view it.

Electrification enables lower fuel costs, reduced maintenance costs, and reduced equipment downtime to significantly decrease operating expenses

BOULDER, Colo.--(BUSINESS WIRE)--#Airports--A new report from Guidehouse Insights examines the electrification opportunities and barriers for seaport cargo handling equipment, airport ground support equipment, and forklifts, providing global market forecasts through 2030.

As the world relies more on shipping and air transit for commerce, emissions from cargo handling equipment are expected to increase. Electrification and low emissions fuels are likely to be crucial in reducing the environmental impacts of this equipment, and are supported by favorable cost economics and supportive decarbonization mandates. Click to tweet: According to a new report from @WeAreGHInsights, by 2030, sales of global electric cargo handling equipment are expected to exceed 1.5 million pieces and account for 60% of total equipment sales.

“Compared with non-electric cargo handling equipment, the price of electric powertrains can be more costly upfront, but lower fuel costs of electricity, reduced maintenance costs, and reduced equipment downtime can significantly decrease operating expenses for fleets,” says Raquel Soat, research analyst with Guidehouse Insights. “Additionally, some cargo handling equipment fleets might be able to participate in grid services such as vehicle-to-grid (V2G), and many will likely use managed charging, which can greatly decrease electrification costs.”

Despite favorable market conditions and an uptick in electric cargo handling equipment volumes, market barriers still exist. According to the report, the availability of electric equipment for niche and heavy duty use cases is limited and technology issues are a consideration. Finally, use cases that do not allow for much downtime, such as busy seaports, might not have the optimal utilization factors for electrification at this point.

The report, Market Data: Cargo Handling Equipment Electrification, provides an outlook on the cargo handling equipment (CHE) population and sales for airport ground support equipment (GSE), seaport CHE, and Classes 1-5 forklifts. Forecasts are provided for the following global regions: North America, Europe, Organisation for Economic Co‑operation and Development Asia Pacific, China, the Rest of Asia Pacific, Latin America, India, and the Middle East & Africa. The report provides insights through 2030 and forecasts on a baseline scenario that accounts for all current market conditions, availability, incentives, and emissions/decarbonization standards. An executive summary of the report is available for free download on the Guidehouse Insights website.

About Guidehouse Insights

Guidehouse Insights, the dedicated market intelligence arm of Guidehouse, provides research, data, and benchmarking services for today’s rapidly changing and highly regulated industries. Our insights are built on in-depth analysis of global clean technology markets. The team’s research methodology combines supply-side industry analysis, end-user primary research, and demand assessment, paired with a deep examination of technology trends, to provide a comprehensive view of emerging resilient infrastructure systems. Additional information about Guidehouse Insights can be found at www.guidehouseinsights.com.

About Guidehouse

Guidehouse is a leading global provider of consulting services to the public and commercial markets with broad capabilities in management, technology, and risk consulting. We help clients address their toughest challenges and navigate significant regulatory pressures with a focus on transformational change, business resiliency, and technology-driven innovation. Across a range of advisory, consulting, outsourcing, and digital services, we create scalable, innovative solutions that prepare our clients for future growth and success. Headquartered in McLean, VA., the company has more than 8,000 professionals in over 50 locations globally. Guidehouse is a Veritas Capital portfolio company, led by seasoned professionals with proven and diverse expertise in traditional and emerging technologies, markets, and agenda-setting issues driving national and global economies. For more information, please visit: www.guidehouse.com.

* The information contained in this press release concerning the report, Market Data: Cargo Handling Equipment Electrification, is a summary and reflects the current expectations of Guidehouse Insights based on market data and trend analysis. Market predictions and expectations are inherently uncertain and actual results may differ materially from those contained in this press release or the report. Please refer to the full report for a complete understanding of the assumptions underlying the report’s conclusions and the methodologies used to create the report. Neither Guidehouse Insights nor Guidehouse undertakes any obligation to update any of the information contained in this press release or the report.

Lindsay Funicello-Paul
+1.781.270.8456
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ALEXANDRIA, Va.--(BUSINESS WIRE)--VSE Corporation (NASDAQ: VSEC), a leading provider of distribution and maintenance, repair and overhaul (MRO) services for land, sea and air transportation assets in the public and private sectors, today announced that it has entered into an exclusive, life-of-program distribution agreement with Pratt & Whitney Canada. Under the terms of the agreement, VSE Aviation will be the exclusive global licensed distributor for new radial parts and inventory of Pratt & Whitney Canada’s APS500 Auxiliary Power Unit (APU) for commercial applications.

Under the terms of the agreement, VSE Aviation is appointed the exclusive licensed distributor for more than 1,500 aftermarket parts and components supporting Pratt & Whitney Canada’s APS500 and the Embraer Regional Jet (ERJ), De Havilland Canada DHC-8 (Dash 8), Gulfstream, Bombardier and Textron aircraft platforms. The agreement term is for the commercial life of the program. The program will be implemented and executed throughout 2021.

“We are very pleased to announce this partnership to support Pratt & Whitney Canada’s APS500 at global MROs, regional airlines and business jet repair centers,” stated John Cuomo, President and CEO of VSE Corporation. “This new award highlights VSE Aviation’s strong technical product expertise and depth of experience managing complex global distribution programs serving the commercial, business jet, and general aviation aftermarket. Further, this award positions us to significantly grow our presence as a leading distributor of flight-critical components, while continuing to leverage the differentiated value proposition we deliver to our customers.”

“This long-term agreement expands our relationship with Pratt & Whitney Canada into APU parts distribution and grows our addressable market into new regional jet platforms, while also broadening our core business jet product portfolio,” stated Ben Thomas, Group President, VSE Aviation. “This announcement, together with our recently announced landing gear initiative, reflects our increased focus on serving high-value products in niche markets. We look forward to supporting Pratt & Whitney Canada as their exclusive solutions partner for this APU in the years ahead.”

“As the APS500 OEM, we will continue to manufacture the APU and provide spare parts to VSE Aviation under an exclusive distribution license,” stated Satheeshkumar Kumarasingam, Vice President of Customer Service, Pratt & Whitney Canada. “We initiated this transaction as part of our ongoing efforts to increase the availability of spare parts to APS500 customers around the world. Given VSE Aviation’s extensive reach into secondary aviation markets, they are well positioned to increase service levels associated with the APS500.”

ABOUT VSE CORPORATION

VSE is a leading provider of aftermarket distribution and repair services for land, sea and air transportation assets for government and commercial markets. Core services include maintenance, repair and overhaul (MRO) services, parts distribution, supply chain management and logistics, engineering support, and consulting and training services for global commercial, federal, military and defense customers. VSE also provides information technology and energy consulting services. For additional information regarding VSE’s services and products, visit us at www.vsecorp.com.

FORWARD LOOKING STATEMENTS

This release contains statements that, to the extent they are not recitations of historical fact, constitute “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. All such statements are intended to be subject to the safe harbor protection provided by applicable securities laws. For discussions identifying some important factors that could cause actual VSE results to differ materially from those anticipated in the forward-looking statements in this news release, see VSE’s public filings with the Securities and Exchange Commission. The forward-looking statements included herein are only made as of the date hereof, and VSE specifically disclaims any obligation to update these statements in the future.

INVESTOR RELATIONS CONTACT: Noel Ryan | Phone: 720.778.2415

CLEVELAND--(BUSINESS WIRE)--Cleveland-Cliffs Inc. (NYSE: CLF) announced today that it has set a target to reduce its greenhouse gas emissions by 25 percent by 2030. This goal represents combined Scope 1 (direct) and Scope 2 (indirect) greenhouse gas emission reductions on a mass basis (metric tons per year) compared with 2017 baseline levels. The Company has published a detailed plan outlining its strategic priorities on its corporate website at www.clevelandcliffs.com.

Lourenco Goncalves, Chairman, President and Chief Executive Officer said, “We at Cleveland-Cliffs acknowledge that one of the most important issues impacting our planet is climate change. The American steel industry is one of the cleanest and most energy efficient in the world, and therefore the utilization of steel Made in the USA is a decisively positive move to protect the planet against massive pollution embedded in the steel produced in other countries.”

Mr. Goncalves added: “In the past year Cleveland-Cliffs has transformed itself into the largest flat-rolled steel producer in North America. As a company currently employing more than 25,000 people, the vast majority of them in good paying middle-class union jobs, our commitment to operating our business in an environmentally and socially responsible manner remains our priority. As we continue to grow the company going forward, we will vigorously pursue the opportunities we have outlined in our Greenhouse Gas Reduction Commitment, and will be transparent with our stakeholders by regularly reporting on our progress.”

Cleveland-Cliffs’ plan is based on its execution of the following five strategic priorities:

1. Developing domestically sourced, high quality iron ore feedstock and utilizing natural gas in the production of hot briquetted iron (HBI);
2. Implementing energy efficiency and green energy projects;
3. Investing in the development of carbon capture technology;
4. Enhancing our greenhouse gas emissions transparency and sustainability focus; and
5. Supporting public policies that facilitate carbon reduction in the domestic steel industry

About Cleveland-Cliffs Inc.

Cleveland-Cliffs is the largest flat-rolled steel producer in North America. Founded in 1847 as a mine operator, Cliffs also is the largest supplier of iron ore pellets in North America. In 2020, Cleveland-Cliffs acquired two major steelmakers, AK Steel Corporation and ArcelorMittal USA LLC, vertically integrating its legacy iron ore business with quality-focused steel production and emphasis on the automotive end market. Cleveland-Cliffs’ fully integrated portfolio includes custom-made pellets and Hot Briquetted Iron (HBI); flat-rolled carbon steel, stainless, electrical, plate, tin and long steel products; as well as carbon and stainless steel tubing, hot and cold stamping and tooling. Headquartered in Cleveland, Ohio, Cleveland-Cliffs employs approximately 25,000 people across its mining, steel and downstream manufacturing operations in the United States and Canada. For more information, visit www.clevelandcliffs.com.

MEDIA CONTACT:

Patricia Persico
Director, Corporate Communications
(216) 694-5316

INVESTOR CONTACT:

Paul Finan
Vice President, Investor Relations
(216) 694-6544

HOUSTON--(BUSINESS WIRE)--SANDRIDGE MISSISSIPPIAN TRUST I (OTC: SDTTU) today announced a quarterly distribution for the three-month period ended December 31, 2020 (which primarily relates to production attributable to the Trust’s interests from September 1, 2020 to November 30, 2020) of approximately $0.1 million, or $0.0029 per unit. The Trust makes distributions on a quarterly basis on or about the 60th day following the completion of each quarter. The distribution is expected to occur on or before February 26, 2021 to holders of record as of the close of business on February 12, 2021.

During the three-month production period ended November 30, 2020, average natural gas and natural gas liquids (“NGL”) prices increased compared to the three-month period ended August 31, 2020. Combined sales volumes slightly decreased compared to the previous period. As no additional development wells will be drilled, the Trust’s production is expected to decline each quarter during the remainder of its life.

As described in the Trust’s annual and quarterly reports filed with the Securities and Exchange Commission (the “SEC”), the trust agreement governing the Trust requires the Trust to dissolve and commence winding up of its business and affairs if cash available for distribution for any four consecutive quarters, on a cumulative basis, is less than $1.0 million. As cash available for distribution for the four consecutive quarters ended September 30, 2020, on a cumulative basis, totaled approximately $815,000, the Trust was required to dissolve and commence winding up beginning as of the close of business on November 13, 2020 (the “dissolution trigger date”). Accordingly, the Trustee is required to sell all of the Trust’s assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders after payment, or reasonable provision for payment, of all Trust liabilities, which is expected to include the establishment of cash reserves in such amounts as the Trustee in its discretion deems appropriate for the purpose of making reasonable provision for all claims and obligations of the Trust, including any contingent, conditional or unmatured claims and obligations, in accordance with the Delaware Statutory Trust Act. The sale process will involve costs that will reduce the amounts of any distributions to unitholders during the winding up period. As required by the trust agreement, the Trustee has engaged a third-party advisor to assist with the marketing and sale of the Trust’s assets. As provided in the trust agreement, SandRidge has a right of first refusal with respect to any sale of assets to a third party. The Trustee expects to complete the sale of the Trust’s assets and distribute the net proceeds of the sale to the Trust unitholders by the third quarter of 2021, and the Trust units are expected to be canceled shortly thereafter. Pending the sale or sales of the royalty interests, the Trust anticipates that it will continue to receive income from the royalty interests and will continue to make quarterly distributions to unitholders to the extent there is available cash after payment of Trust expenses and additions to cash reserves. The Trust will remain in existence until the filing of a certificate of cancellation with the Secretary of State of the State of Delaware following the completion of the winding up process.

The Trust owns royalty interests in oil and natural gas properties in the Mississippian formation in Alfalfa, Garfield, Grant and Woods counties in Oklahoma and is entitled to receive proceeds from the sale of production attributable to the royalty interests. As described in the Trust’s filings with the Securities and Exchange Commission (the “SEC”), the amount of the quarterly distributions is expected to fluctuate from quarter to quarter, depending on the proceeds received by the Trust as a result of actual production volumes, oil, natural gas and NGL prices, and the amount and timing of the Trust’s administrative expenses, among other factors. All Trust unitholders share distributions on a pro rata basis.

Volumes, average prices and distributable income available to unitholders for the period were (dollars in thousands, except average prices and per unit amount):

As previously disclosed, commencing with the distribution to unitholders paid in the first quarter of 2019, the Trustee has withheld, and in the future intends to withhold, the greater of $35,000 or 3.5% of the funds otherwise available for distribution to Trust unitholders each quarter to gradually increase cash reserves for the payment of future known, anticipated or contingent expenses or liabilities by a total of approximately $1,425,000. In light of the early termination of the Trust, the Trustee has elected to withhold approximately $96,000, the remaining amount needed to reach its targeted cash reserve. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities of the Trust eventually will be distributed to unitholders, together with interest earned on the funds.

Pursuant to Internal Revenue Code Section 1446, withholding tax on income effectively connected to a United States trade or business allocated to non-U.S. persons ("ECI") should be made at the highest marginal rate. Under Section 1441, withholding tax on fixed, determinable, annual, periodic income from United States sources allocated to non-U.S. persons should be made at 30% of gross income unless the rate is reduced by treaty. This is intended to be a qualified notice by SandRidge Mississippian Trust I to nominees and brokers as provided for under Treasury Regulation Section 1.1446-4(b), and while specific relief is not specified for Section 1441 income, this disclosure is intended to suffice. Nominees and brokers should withhold at the highest marginal rate on the distribution made to non-U.S. persons. The Tax Cuts and Jobs Act (the "TCJA") enacted in December 2017 treats a non-U.S. holder's gain on the sale of Trust units as ECI to the extent such holder would have had ECI if the Trust had sold all of its assets at fair market value on the date of the exchange. The TCJA also requires the transferee of units to withhold 10% of the amount realized on the sale of exchange of units (generally, the purchase price) unless the transferor certifies that it is not a nonresident alien individual or foreign corporation. Pending the finalization of proposed regulations under IRC Section 1446, the IRS has suspended this new withholding obligation with respect to publicly traded partnerships such as the Trust, which is classified as a partnership for federal and state income tax purposes.

This press release contains statements that are “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. All statements contained in this press release, other than statements of historical facts, are “forward-looking statements” for purposes of these provisions. These forward-looking statements include the amount and date of any anticipated distribution to unitholders; expectations regarding the timing of the completion of the sale process and the winding up of the Trust, including the cancellation of the Trust units; expectations regarding the costs involved in the sale process; and statements regarding the possibility of future distributions to unitholders during the winding up period. The anticipated distribution is based, in part, on the amount of cash received or expected to be received by the Trust from SandRidge with respect to the relevant period. Any differences in actual cash receipts by the Trust could affect this distributable amount. The amount of such cash received or expected to be received by the Trust (and its ability to pay distributions) has been and will be significantly and negatively impacted by prevailing low commodity prices, which have declined sharply since the beginning of 2020 in response to the economic effects of the COVID-19 pandemic and the announcement in March 2020 of planned production increases by Saudi Arabia and could remain low for an extended period of time or decline further. Continued low oil, NGL and natural gas prices will reduce revenues to the Trust, which will reduce the amount of cash available for distribution to unitholders and in certain periods could result in no distributions to unitholders. Other important factors that could cause actual results to differ materially include expenses of the Trust and reserves for anticipated future expenses, and the effect, impact, potential duration or other implications of the COVID-19 pandemic. Statements made in this press release are qualified by the cautionary statements made in this press release. Neither SandRidge nor the Trustee intends, and neither assumes any obligation, to update any of the statements included in this press release. An investment in Common Units issued by SandRidge Mississippian Trust I is subject to the risks described in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2019, the Trust’s Quarterly Report on Form 10-Q for the period ended September 30, 2020, and all of its other filings with the SEC. The Trust’s annual, quarterly and other filed reports are or will be available over the Internet at the SEC’s website at http://www.sec.gov.

SandRidge Mississippian Trust I
The Bank of New York Mellon Trust Company, N.A., as Trustee
Sarah Newell
1(512) 236-6555

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

DALLAS--(BUSINESS WIRE)--Energy Transfer LP (NYSE: ET) today announced a quarterly cash distribution of $0.1525 per ET common unit ($0.61 on an annualized basis) for the fourth quarter ended December 31, 2020. The announced quarterly distribution is consistent with the distribution for the third quarter of 2020 and will be paid on February 19, 2021 to unitholders of record as of the close of business on February 8, 2021.

Fourth Quarter and Full Year 2020 Earnings Release and Conference Call

In addition, Energy Transfer plans to release earnings for the fourth quarter and full year 2020 on Wednesday, February 17, 2021, after the market closes. The company will conduct a conference call on Wednesday, February 17, 2021 at 4:00 p.m. Central Time/5:00 p.m. Eastern Time to discuss quarterly results and provide a company update including an outlook for 2021. The conference call will be broadcast live via an internet webcast, which can be accessed on Energy Transfer’s website at energytransfer.com. The call will also be available for replay on Energy Transfer’s website for a limited time.

Energy Transfer LP (NYSE: ET) owns and operates one of the largest and most diversified portfolios of energy assets in the United States, with a strategic footprint in all of the major domestic production basins. ET is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (NGL) and refined product transportation and terminalling assets; NGL fractionation; and various acquisition and marketing assets. ET, through its ownership of Energy Transfer Operating, L.P., also owns Lake Charles LNG Company, as well as the general partner interests, the incentive distribution rights and 28.5 million common units of Sunoco LP (NYSE: SUN), and the general partner interests and 46.1 million common units of USA Compression Partners, LP (NYSE: USAC). For more information, visit the Energy Transfer website at energytransfer.com.

Forward-Looking Statements

This press release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnership’s Annual Report on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. In addition to the risks and uncertainties previously disclosed, the Partnership has also been, or may in the future be, impacted by new or heightened risks related to the COVID-19 pandemic, and we cannot predict the length and ultimate impact of those risks. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.

This release serves as qualified notice to nominees as provided for under Treasury Regulation section 1.1446-4(b)(4) and (d). Please note that 100 percent of Energy Transfer LP’s distributions to foreign investors are attributable to income that is effectively connected with a United States trade or business. Accordingly, all of Energy Transfer LP’s distributions to foreign investors are subject to federal tax withholding at the highest applicable effective tax rate. Nominees, and not Energy Transfer LP, are treated as withholding agents responsible for withholding distributions received by them on behalf of foreign investors.

The information contained in this press release is available on our website at energytransfer.com.

Investor Relations:
Bill Baerg
Brent Ratliff
Lyndsay Hannah
214-981-0795

Media Relations:
Vicki Granado
214-840-5820

• 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

HOUSTON--(BUSINESS WIRE)--USD Partners LP (NYSE: USDP) (the “Partnership”) announced today that the Board of Directors of its general partner declared a quarterly cash distribution of $0.111 per unit for the fourth quarter of 2020 ($0.444 per unit on an annualized basis), the same amount as distributed in the prior quarter. The distribution is payable on February 19, 2021, to unitholders of record at the close of business on February 10, 2021.

Fourth Quarter 2020 Earnings Release Date and Conference Call Information

The Partnership plans to report fourth quarter 2020 financial and operating results after market close on Wednesday March 3, 2021. The Partnership will host a conference call and webcast regarding fourth quarter 2020 results at 11:00 a.m. Eastern Time (10:00 a.m. Central Time) on Thursday, March 4, 2021.

To listen live over the Internet, participants are advised to log on to the Partnership’s website at www.usdpartners.com and select the “Events & Presentations” sub-tab under the “Investors” tab. To join via telephone, participants may dial (877) 266-7551 domestically or +1 (339) 368-5209 internationally, conference ID 3094936. Participants are advised to dial in at least five minutes prior to the call.

An audio replay of the conference call will be available for thirty days by dialing (800) 585-8367 domestically or +1 (404) 537-3406 internationally, conference ID 3094936. In addition, a replay of the audio webcast will be available by accessing the Partnership's website after the call is concluded.

About USD Partners LP

USD Partners LP is a fee-based, growth-oriented master limited partnership formed in 2014 by US Development Group, LLC (“USDG”) to acquire, develop and operate midstream infrastructure and complementary logistics solutions for crude oil, biofuels and other energy-related products. The Partnership generates substantially all of its operating cash flows from multi-year, take-or-pay contracts with primarily investment grade customers, including major integrated oil companies, refiners and marketers. The Partnership’s principal assets include a network of crude oil terminals that facilitate the transportation of heavy crude oil from Western Canada to key demand centers across North America. The Partnership’s operations include railcar loading and unloading, storage and blending in on-site tanks, inbound and outbound pipeline connectivity, truck transloading, as well as other related logistics services. In addition, the Partnership provides customers with leased railcars and fleet services to facilitate the transportation of liquid hydrocarbons and biofuels by rail.

USDG, which owns the general partner of USD Partners LP, is engaged in designing, developing, owning, and managing large-scale multi-modal logistics centers and energy-related infrastructure across North America. USDG solutions create flexible market access for customers in significant growth areas and key demand centers, including Western Canada, the U.S. Gulf Coast and Mexico. Among other projects, USDG, along with its partner Gibson Energy, Inc., is pursuing long-term solutions to transport heavier grades of crude oil produced in Western Canada through the construction of a Diluent Recovery Unit at the Hardisty terminal, which is expected to be placed into service late in the second quarter or early in the third quarter of 2021. USDG is also currently pursuing the development of a premier energy logistics terminal on the Houston Ship Channel with capacity for substantial tank storage, multiple docks (including barge and deepwater), inbound and outbound pipeline connectivity, as well as a rail terminal with unit train capabilities. For additional information, please visit texasdeepwater.com. Information on USDG’s website is not part of this press release.

Qualified Notice to Nominees

This release serves as qualified notice to nominees as provided for under Treasury Regulation Section 1.1446-4(b)(4) and (d). Please note that we believe that 100 percent of the Partnership’s distributions to foreign investors are attributable to income that is effectively connected with a United States trade or business. Accordingly, all of the Partnership’s distributions to foreign investors are subject to federal income tax withholding at the highest effective tax rate for individuals or corporations, as applicable. Nominees, and not the Partnership, are treated as withholding agents responsible for withholding distributions received by them on behalf of foreign investors.

Cautionary Note Regarding Forward-Looking Statements

This press release contains forward-looking statements within the meaning of U.S. federal securities laws, including statements with respect to the amount and timing of the Partnership’s fourth quarter 2020 cash distribution and the business prospects of the Partnership and USDG. Words and phrases such as “plans,” “expects,” “will,” “pursuing,” and similar expressions are used to identify such forward-looking statements. However, the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements relating to the Partnership are based on management’s expectations, estimates and projections about the Partnership, its interests, USDG’s projects and the energy industry in general on the date this press release was issued. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. The current economic downturn and pandemic introduces unusual risks and an inability to predict all risks that may impact the Partnership’s business and outlook. Therefore, actual outcomes and results may differ materially from what is expressed or forecast in such forward-looking statements. Factors that could cause actual results or events to differ materially from those described in the forward-looking statements include those as set forth under the heading “Risk Factors” in the Partnership’s most recent Annual Report on Form 10-K and in its subsequent filings with the Securities and Exchange Commission. The Partnership is under no obligation (and expressly disclaims any such obligation) to update or alter its forward-looking statements, whether as a result of new information, future events or otherwise.

Category: Earnings

Investor Relations Contacts:
Adam Altsuler, (281) 291-3995
Senior Vice President and Chief Financial Officer

Jennifer Waller, (832) 991-8383
Director, Financial Reporting and Investor Relations

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.