CALGARY, Alberta--(BUSINESS WIRE)--(TSE: IMO, NYSE American: IMO) Brad Corson, chairman, president and chief executive officer, and Dave Hughes, vice-president investor relations, Imperial Oil Limited, will host the company's 2020 Investor Day on Thursday, November 19. The event begins at 8 a.m. MT (10 a.m. ET) and will be accessible by webcast.

At Investor Day, Imperial's management team will provide an update on the company’s operations and business strategy, followed by a question-and-answer session.

Please click here [https://edge.media-server.com/mmc/p/gadpjdfk] to register for the live webcast of Imperial's 2020 Investor Day. The webcast will be available for one year on the company’s website at www.imperialoil.ca/en-ca/company/investors.

After more than a century, Imperial continues to be an industry leader in applying technology and innovation to responsibly develop Canada’s energy resources. As Canada’s largest petroleum refiner, a major producer of crude oil, a key petrochemical producer and a leading fuels marketer from coast to coast, our company remains committed to high standards across all areas of our business.

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Low Breakeven Production Driving Powerful Cash Flow Generation

Extraordinary & Quarterly Cash Dividend and Share Buyback Program

Re-engaged Work Program and Initiated Drilling on the CPO-5 Block

BOGOTA, Colombia--(BUSINESS WIRE)--GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Peru, Argentina, Brazil, Chile and Ecuador reports its consolidated financial results for the three-month period ended September 30, 2020 (“Third Quarter” or “3Q2020”). A conference call to discuss 3Q2020 financial results and the work program and investment guidelines for 2021 will be held on November 5, 2020 at 10:00 am (Eastern Standard Time).

All figures are expressed in US Dollars and growth comparisons refer to the same period of the prior year, except when specified. Definitions and terms used herein are provided in the Glossary at the end of this document. This release does not contain all of the Company’s financial information and should be read in conjunction with GeoPark’s consolidated financial statements and the notes to those statements for the period ended September 30, 2020 and 2019, available on the Company’s website.

THIRD QUARTER 2020 HIGHLIGHTS

Expanded Production and Restarted Work Program

• Consolidated oil and gas production of 38,845 boepd in 3Q2020, up 5% compared to 2Q2020
• Resumed drilling with three wells put on production in the Llanos 34 block (GeoPark operated, 45% WI)
• Reopened temporarily shut-in production and producing 40,000 boepd by the end of 3Q2020
• Currently drilling the Indico 2 appraisal well in the CPO-5 block (GeoPark non-operated, 30% WI)

Implemented Decisive Cost and Investment Reduction Plan

• Cost and investment reductions totaled over $290 million across regional platform
• Further improving GeoPark’s cost efficiencies with ongoing cost-cutting initiatives at all levels
• Production and operating costs reduced by 32% to $28.4 million
• Operating costs per boe¹ reduced by 22% to $6.3 per boe
• G&A/G&G costs reduced by 30% to $13.1 million

Generated Substantial Free Cash Flow

• Revenue of $98.1 million
• Adjusted EBITDA of $56.1 million (or $15.9 per boe), 2x Adjusted EBITDA in 2Q2020
• Operating Profit of $28.5 million / Net Loss of $4.3 million
• Capital expenditures reduced by 56% to $9.8 million
• Full-year 2020 work program of $65-75 million targeting 40,000-42,000 boepd annual average production and operating netbacks of $245-270 million assuming Brent of $35-40 per bbl²

Built Strong Financial Position and Risk Management

• $163.7 million cash ($157.5 million in 2Q2020 and after interest payments of $23.5 million in 3Q2020)
• $75 million oil prepayment facility, with $50 million committed and no amounts drawn
• $132.9 million in uncommitted credit lines
• Long-term financial debt maturity profile with no principal payments until September 2024
• Continuously adding new hedges for the next 15 months

Increased SPEED/ESG+ Response and Actions

• Protocols, preventive measures and crisis response plans in place across six-country regional platform
• Field teams sharply reduced to a minimum with back-up teams and contingencies in place to keep people working safely and production flowing
• GeoPark closely engaged with local communities implementing a significant range of measures to fight Covid-19 with efforts coordinated at local, regional and federal levels
• Appointment of Sylvia Escovar and Somit Varma as new independent members of GeoPark’s Board of Directors (filling vacancies)
• Released GeoPark's Environmental, Social and Governance ("ESG") report for 2019, available on the Company's website

Returning Value to Shareholders by Cash Dividends and Share Buyback Program

• 2020 Extraordinary Cash Dividend of $0.0206 per share ($1.25 million) payable on December 9, 2020
• 2020 Quarterly Dividend of $0.0206 per share ($1.25 million) payable on December 9, 2020
• Resuming discretionary share buyback program for up to 10% of total outstanding shares

James F. Park, Chief Executive Officer of GeoPark, said: “Thanks to and admiration for the GeoPark team for again performing through this monster storm. Because of its quick, decisive and significant moves, GeoPark today is in a position to re-engage our work program, grow production, build and set into motion an attractive work program for 2021 and begin returning cash to its shareholders in the fourth quarter. And, beyond just surviving the collapse and accommodating to the new environment, our team transformed GeoPark – from a cost, capability, and organizational perspective – into a better and stronger company ready to capture the immense opportunity ahead.”

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

Production: Overall oil and gas production decreased by 2% to 38,845 boepd in 3Q2020 from 39,619 boepd in 3Q2019, due to reopened shut-in production and limited drilling and maintenance activities during the quarter, partially offset by the addition of production from the recent Amerisur Resources Plc (“Amerisur”) acquisition in Colombia. Oil represented 85% of total reported production in 3Q2020 and 3Q2019.

For further details, please refer to the 3Q2020 Operational Update published on October 14, 2020.

Reference and Realized Oil Prices: Brent crude oil prices averaged $43.3 per bbl during 3Q2020, $18.6 per bbl lower than 3Q2019 levels. Consolidated realized oil sales price averaged $31.7 per bbl in 3Q2020, $17.6 per bbl lower than the $49.3 per bbl in 3Q2019, reflecting a higher local marker differential in Colombia that was partially offset by lower commercial and transportation discounts.

In Colombia, the local marker differential to Brent averaged $3.0 per bbl in 3Q2020, compared to $6.5 per bbl in 2Q2020 and $1.7 per bbl in 3Q2019. Commercial and transportation discounts improved by $2.1 per bbl and averaged $9.0 per bbl in 3Q2020, compared to $11.1 per bbl in 3Q2019, resulting from further improvements achieved for production in the Llanos 34 block plus the addition of the Platanillo (GeoPark operated, 100% WI) and CPO-5 blocks as part of the Amerisur acquisition, both of which have lower commercial and transportation discounts.

The tables below provide a breakdown of reference and net realized oil prices in Colombia, Chile and Argentina in 3Q2020 and 3Q2019:

Revenue: Consolidated revenue decreased by 35% to $98.1 million in 3Q2020, compared to $151.2 million in 3Q2019 reflecting lower oil and gas prices.

Sales of crude oil: Consolidated oil revenue decreased by 35% to $89.3 million in 3Q2020, driven by a 36% decrease in realized oil prices and flat deliveries. Oil revenue was 91% of total revenue in 3Q2020 and 3Q2019.

• Colombia: In 3Q2020, oil revenue decreased by 36% to $82.8 million reflecting lower realized oil prices and a 1% increase in oil deliveries. Realized prices decreased by 36% to $31.3 per bbl due to lower Brent oil prices and a higher Vasconia differential, partially compensated by lower commercial and transportation discounts. Oil deliveries increased by 1% to 29,962 bopd, reflecting the recent acquisition of Amerisur that was partially offset by temporary shut-ins and limited drilling and maintenance activity. Colombian earn-out payments decreased by 42% to $3.4 million in 3Q2020, compared to $6.0 million in 3Q2019, in line with lower oil revenue in the Llanos 34 block.
• Chile: In 3Q2020, oil revenue decreased by 49% to $1.2 million, due to lower oil prices and volumes sold. Realized oil prices decreased by 36% to $35.0 per bbl, in line with lower Brent prices. Oil deliveries decreased by 21% to 361 bopd due to limited maintenance works and no drilling activity, combined with the natural decline of the fields.
• Argentina: In 3Q2020, oil revenue decreased by 21% to $5.3 million due to lower oil prices and to a lesser extent, lower deliveries. Realized oil prices decreased by 17% to $40.5 per bbl due to the dissociation of local oil prices from international oil prices whereas oil deliveries decreased by 4% to 1,424 bopd due to limited maintenance works and no drilling activity, combined with the natural decline of the fields.

Sales of gas: Consolidated gas revenue decreased by 32% to $8.8 million in 3Q2020 compared to $13.0 million in 3Q2019 reflecting 43% lower gas prices, partially offset by a 19% increase in volumes delivered. Gas revenue was 9% of total revenue in both 3Q2020 and 3Q2019.

• Chile: In 3Q2020, gas revenue decreased by 28% to $4.2 million reflecting lower gas prices, partially offset by higher gas deliveries. Gas prices were 42% lower, or $2.3 per mcf ($14.1 per boe) in 3Q2020 due to lower methanol prices. The successful development of the Jauke gas field and the recent discovery of the Jauke Oeste gas field in early 2020 increased gas deliveries by 25% to 19,374 mcfpd (3,229 boepd).
• Brazil: In 3Q2020, gas revenue decreased by 42% to $3.3 million, due to lower gas deliveries and lower gas prices. Gas deliveries fell by 30% in the Manati gas field (GeoPark non-operated, 10% WI) to 8,661 mcfpd (1,443 boepd) due to lower gas demand in Brazil. Gas prices decreased by 16% to $4.1 per mcf ($24.8 per boe), due to the impact of the local currency devaluation, which was partially offset by the annual price inflation adjustment of approximately 7%, effective in January 2020.
• Argentina: In 3Q2020, gas revenue decreased by 15% to $0.8 million, resulting from lower gas prices, partially offset by higher deliveries. Gas prices decreased by 28% to $2.1 per mcf ($12.4 per boe) due to local market conditions while deliveries increased by 18% to 4,320 mcfpd (720 boepd) due to optimization activities focused on enhancing base production levels and the improved performance of the Challaco Bajo gas field.

Commodity Risk Management Contracts: Consolidated commodity risk management contracts amounted to a $2.7 million gain in 3Q2020, compared to a $4.4 million gain in 3Q2019.

Commodity risk management contracts have two different components, a realized and an unrealized portion.

The realized portion of the commodity risk management contracts registered a cash gain of $1.4 million in both 3Q2020 and 3Q2019. Realized gains in 3Q2020 resulted from hedges in place providing protection to prevailing oil prices during 3Q2020.

The unrealized portion of the commodity risk management contracts amounted to a $1.3 million gain in 3Q2020, compared to a $3.0 million gain in 3Q2019. Unrealized gains during 3Q2020 resulted from a slight decrease in the forward Brent oil price curve compared to June 2020 and the impact of new hedges added during 3Q2020 as measured at September 30, 2020.

GeoPark recently added new oil hedges further increasing its low-price risk protection over the next 15 months. Please refer to the “Commodity Risk Oil Management Contracts” section below for a description of hedges in place as of the date of this release.

Production and Operating Costs³: Consolidated production and operating costs decreased by 32% to $28.4 million from $41.7 million resulting from lower royalties and lower operating costs per boe.

The table below provides a breakdown of production and operating costs in 3Q2020 and 3Q2019:

Consolidated operating costs decreased by 25%, or $6.7 million to $19.9 million in 3Q2020 compared to $26.6 million in 3Q2019. Consolidated operating costs per boe decreased to $6.3 in 3Q2020 from $8.1 per boe in 3Q2019.The breakdown of operating costs is as follows:

• Colombia: Operating costs per boe increased by 5% to $5.9 in 3Q2020 compared to $5.6 in 3Q2019. Total operating costs remained flat and amounted to $15.2 million, due to the addition of the Platanillo block as part of the Amerisur acquisition, which has higher costs per boe than the Llanos 34 block, partially offset by ongoing cost reduction efforts and the effect of the devaluation of the local currency.
• Chile: Operating costs per boe decreased by 72% to $5.3 in 3Q2020 compared to $19.3 in 3Q2019, due to ongoing cost reduction efforts (including lower well intervention activities, efficiencies and the renegotiation of existing contracts) and to a lesser extent, to the devaluation of the local currency. Total operating costs decreased by 67% to $1.8 million in 3Q2020 from $5.4 million in 3Q2019, despite an increase of 18% in oil and gas deliveries.
• Brazil: Operating costs per boe decreased by 27% to $5.8 in 3Q2020 compared to $7.9 in 3Q2019 mainly reflecting the impact of the devaluation of the local currency. Total operating costs decreased by $0.7 million to $0.3 million in 3Q2020 compared to $1.0 million in 3Q2019, reflecting lower operating costs per boe and lower production and deliveries in Manati gas field, which decreased by 31%.
• Argentina: Operating costs per boe decreased by 45% to $14.9 in 3Q2020 compared to $27.0 in 3Q2019 due to ongoing cost reduction efforts (including lower well intervention activities, efficiencies and the renegotiation of existing contracts) and to a lesser extent, due to the devaluation of the local currency. Total operating costs decreased by 45% to $2.8 million in 3Q2020 compared to $4.9 million in 3Q2019 due to lower operating costs per boe, partially offset by a 2% increase oil and gas deliveries.

Consolidated royalties fell by 45% or $6.7 million to $8.4 million in 3Q2020 compared to $15.1 million in 3Q2019, mainly resulting from lower oil prices, partially offset by a 3% increase in oil and gas deliveries.

Selling Expenses: Consolidated selling expenses decreased by $1.1 million to $1.3 million in 3Q2020 (of which $0.8 million, or $0.3 per bbl, correspond to Colombia), compared to $2.4 million in 3Q2019.

Administrative Expenses: Consolidated G&A costs per boe decreased by 41% to $2.5⁴ in 3Q2020 compared to $4.2 in 3Q2019 due to ongoing cost reduction initiatives that even outweighed the incremental G&A costs related to the addition of Amerisur operations. Total consolidated G&A decreased by $4.1 million to $10.4 million in 3Q2020 compared to $14.5 million in 3Q2019.

Geological & Geophysical Expenses: Consolidated G&G costs per boe decreased by 56% to $0.8⁵ in 3Q2020 versus $1.8 in 3Q2019 due to ongoing cost reduction initiatives and despite incremental G&G costs related to the addition of Amerisur operations. Total consolidated G&G expenses decreased by $1.5 million to $2.8 million in 3Q2020 compared to $4.3 million in 3Q2019.

Adjusted EBITDA: Consolidated Adjusted EBITDA⁶ decreased by 35% to $56.1 million, or $15.9 per boe, in 3Q2020 compared to $86.7 million, or $25.3 per boe, in 3Q2019.

• Colombia: Adjusted EBITDA of $53.4 million in 3Q2020
• Chile: Adjusted EBITDA of $2.7 million in 3Q2020
• Brazil: Adjusted EBITDA of $1.9 million in 3Q2020
• Argentina: Adjusted EBITDA of $0.4 million in 3Q2020
• Corporate, Ecuador and Peru: Adjusted EBITDA of negative $2.2 million in 3Q2020

The table below shows production, volumes sold and the breakdown of the most significant components of Adjusted EBITDA for 3Q2020 and 3Q2019, on a per country and per boe basis:

Depreciation: Consolidated depreciation charges increased by 1% to $26.7 million in 3Q2020, compared to $26.5 million in 3Q2019, in line with a slight increase in volumes delivered.

Write-off of unsuccessful exploration efforts: The consolidated write-off of unsuccessful exploration efforts amounted to $0.6 million in 3Q2020 compared to $8.4 million in 3Q2019. Amounts recorded in 3Q2019 mainly refer to unsuccessful exploration wells and other exploration costs incurred in the CN-V (GeoPark non-operated, 50% WI) and Sierra del Nevado (GeoPark non-operated, 18% WI) blocks in Argentina.

Impairment of Non-Financial Assets: Consolidated non-cash impairment of non-financial assets amounted to $1.0 million in 3Q2020 and is related to the REC-T 128 block (GeoPark operated, 70% WI) in Brazil that was classified as an asset held for sale as of September 30, 2020. A non-cash impairment loss is recognized for the amount by which an asset’s carrying amount exceeds its recoverable amount.

Other Income (Expenses): Other operating expenses were $1.3 million in 3Q2020, compared to $1.4 million in 3Q2019.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Financial Expenses: Net financial expenses increased to $15.8 million in 3Q2020, compared to $8.6 million in 3Q2019 mainly resulting from higher interest expenses related to the issuance of $350 million notes due in 2027 (2027 Notes).

Foreign Exchange: Net foreign exchange charges added a $0.7 million loss in 3Q2020 compared to a $0.8 million gain in 3Q2019.

Income Tax: Income taxes totaled $16.3 million loss in 3Q2020 compared to $41.8 million loss in 3Q2019, mainly resulting from lower profits before income taxes and the effect of fluctuations of local currencies over deferred income taxes.

Profit: Loss of $4.3 million in 3Q2020 compared to a $6.8 million profit recorded in 3Q2019, mainly due to lower operating profits and higher financial expenses, partially offset by lower income taxes.

BALANCE SHEET

Cash and Cash Equivalents: Cash and cash equivalents totaled $163.7 million as of September 30, 2020 compared to $111.2 million as of December 31, 2019. Cash generated from operating activities equaled $91.6 million and cash generated from financing activities equaled $284.2 million, partially offset by cash used in investing activities of $321.6 million.

Cash generated from financing activities of $284.2 million mainly included net proceeds from the issuance of the 2027 Notes of $342.5 million, partially offset by interest payments of $37.5 million, lease payments of $7.3 million, $4.5 million related to the acquisition of the LG International Corp’s non-controlling interest in Colombia and Chile in 2018, short-term principal payments of $3.6 million and share repurchase payments of $3.0 million.

Cash used in investing activities of $321.6 million included the acquisition of Amerisur of $272.3 million (net of cash received), and organic capital expenditures of $49.3 million.

Financial Debt: Total financial debt net of issuance cost was $772.2 million, including the 2024 Notes, the 2027 Notes and other short-term bank loans totaling $3.5 million. Short-term financial debt was $4.8 million as of September 30, 2020.

For further details, please refer to Note 12 of GeoPark’s consolidated financial statements as of September 30, 2020, available on the Company’s website.

FINANCIAL RATIOS^a

Covenants in 2024 Notes: The 2024 Notes include incurrence test covenants that require the net debt to Adjusted EBITDA ratio to be lower than 3.25 times and the Adjusted EBITDA to interest ratio to be higher than 2.25 times until September 2021. As of the date of this release the Company is compliant with both covenants.

Issuance of 2027 Notes: In January 2020, the Company issued $350 million of 5.5% notes due in 2027 (2027 Notes) in accordance with Rule 144A under the United States Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the United States Securities Act.

INVESTORS:
Stacy Steimel – Shareholder Value Director
Santiago, Chile
T: +562 2242 9600
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Miguel Bello – Market Access Director
Santiago, Chile
T: +562 2242 9600
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MEDIA:
Communications Department
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DALLAS--(BUSINESS WIRE)--Energy Transfer LP (NYSE:ET) (“ET” or the “Partnership”) today reported financial results for the quarter ended September 30, 2020.

ET reported an earnings net loss attributable to partners for the three months ended September 30, 2020 of $782 million, which included non-cash impairments of goodwill and joint venture investments totaling $1.6 billion.

Adjusted EBITDA for the three months ended September 30, 2020 was $2.87 billion compared with $2.81 billion for the three months ended September 30, 2019. Results included record operating performance in the Partnership’s NGL and refined products segment.

Distributable Cash Flow attributable to partners, as adjusted, for the three months ended September 30, 2020 was $1.69 billion compared to $1.55 billion for the three months ended September 30, 2019. The change between periods reflected the increase in Adjusted EBITDA, along with a decrease in maintenance capital expenditures.

ET once again reduced its 2020 growth capital outlook. As a result of project cost savings, the Partnership now expects to invest less than $3.3 billion for the full-year 2020, which is more than $100 million below previous estimates.

In addition, due to Partnership performance this year and improving market conditions, ET now expects to have full-year results at the high end of its 2020 outlook for Adjusted EBITDA range of $10.2 billion to $10.5 billion.

Key accomplishments and current developments:

Operational

• As the COVID-19 pandemic continues, our field operations have continued uninterrupted, and remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations nor caused us to incur significant additional expenses.
• For the third quarter of 2020, ET achieved record high transportation and fractionation volumes in its NGL and refined products transportation and services segment.
• The Partnership successfully managed operations through two major hurricanes hitting the Gulf Coast without an employee safety incident and without any significant service disruption to our customers.

Strategic

• During the third quarter of 2020, the Partnership completed its Lone Star Express expansion under budget and ahead of schedule.
• The Partnership has also continued to make significant progress on other major capital projects throughout the U.S. The Partnership currently expects the next phase of Mariner East, Orbit and other NGL export projects to be placed in service by year-end.

Financial

• In October 2020, ET announced a quarterly distribution of $0.1525 per unit ($0.61 annualized) on ET common units for the quarter ended September 30, 2020. The distribution coverage ratio for the third quarter of 2020 was 4.10x. ET expects to use the excess cash resulting from this distribution decrease to reduce debt.
• As of September 30, 2020, Energy Transfer Operating, L.P.’s (“ETO”) $6.00 billion revolving credit facilities had an aggregate $2.65 billion of available capacity, and the leverage ratio, as defined by the credit agreement, was 4.24x.
• ET has also updated its 2020 outlook with reduced capex and improved Adjusted EBITDA expectations.

ET benefits from a portfolio of assets with exceptional product and geographic diversity. The Partnership’s multiple segments generate high-quality, balanced earnings with no single segment contributing more than 30% of the Partnership’s consolidated Adjusted EBITDA for the three months ended September 30, 2020. The vast majority of the Partnership’s segment margins are fee-based and therefore have limited commodity price sensitivity.

Conference Call information:

The Partnership has scheduled a conference call for 4:00 p.m. Central Time, Wednesday, November 4, 2020 to discuss its third quarter 2020 results and provide a partnership update. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com or ir.energytransfer.com and will also be available for replay on the Partnership’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, 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 LP website at www.energytransfer.com.

Sunoco LP (NYSE: SUN) is a master limited partnership with core operations that include the distribution of motor fuel to approximately 10,000 convenience stores, independent dealers, commercial customers and distributors located in more than 30 states, as well as refined product transportation and terminalling assets. SUN’s general partner is owned by Energy Transfer Operating, L.P., a subsidiary of Energy Transfer LP (NYSE: ET). For more information, visit the Sunoco LP website at www.sunocolp.com.

USA Compression Partners, LP (NYSE: USAC) is a growth-oriented Delaware limited partnership that is one of the nation’s largest independent providers of compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of producers, processors, gatherers and transporters of natural gas and crude oil. USAC focuses on providing compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities and transportation applications. For more information, visit the USAC website at www.usacompression.com.

Forward-Looking Statements

This news 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, including the Partnership’s Quarterly Report on Form 10-Q to be filed for the current period. 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 the recent decline in commodity prices, 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.

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

There are material limitations to using measures such as Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio, including the difficulty associated with using any such measure as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as operating income, net income and cash flow from operating activities.

Definition of Adjusted EBITDA

We define Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.

Definition of Distributable Cash Flow

We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and deferred income taxes. For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow.

Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.

On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ET’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:

• For subsidiaries with publicly traded equity interests, other than ETO, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to our partners includes distributions to be received by the parent company with respect to the periods presented.
• For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiaries, but Distributable Cash Flow attributable to partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest.

For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related adjustments and non-recurring expenses that are included in net income are excluded.

Definition of Distribution Coverage Ratio

Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to partners, as adjusted, divided by distributions expected to be paid to the partners of ET in respect of such period.

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.

In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

Intrastate Transportation and Storage

Transported volumes decreased primarily due to the bankruptcy filing of a transportation customer.

Energy Transfer
Investor Relations:
Bill Baerg, Brent Ratliff, Lyndsay Hannah, 214-981-0795
or
Media Relations:
Vicki Granado, 214-840-5820

BOGOTA, Colombia--(BUSINESS WIRE)--GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Peru, Argentina, Brazil, Chile and Ecuador today announced its Board of Directors has declared an extraordinary cash dividend of $0.0206 per share for 2020 and a quarterly dividend of $0.0206 per share, both payable on December 9, 2020. In addition, the Board of Directors has approved a buyback program to repurchase up to 10% of its shares outstanding, or approximately 6,062,000 shares.

Extraordinary Cash Dividend

• The Board of Directors has declared an extraordinary cash dividend of $0.0206 per share ($1.25 million in the aggregate) payable on December 9, 2020 to the shareholders of record at the close of business on November 20, 2020

Quarterly Cash Dividend

• The Board of Directors has declared a quarterly cash dividend of $0.0206 per share ($1.25 million in the aggregate) payable on December 9, 2020 to the shareholders of record at the close of business on November 20, 2020

Share Buyback Program

• The buyback program will begin on November 5, 2020 and will expire on November 15, 2021
• The share repurchases may be made from time to time through open market transactions, block trades, privately negotiated transactions or otherwise and are subject to market and business conditions, levels of available liquidity, cash requirements for other purposes, regulatory, and other relevant factors

As detailed in our 2021 Work Program and Investment Guidelines, GeoPark plans to deliver another year of strong operational and financial performance and free cash flow generation while remaining committed to returning value to its shareholders.

GeoPark can be visited online at www.geo-park.com.

NOTICE

Additional information about GeoPark can be found in the “Investor Support” section on the website at www.geo-park.com.

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

This press release contains statements that constitute forward-looking statements. Many of the forward-looking statements contained in this press release can be identified by the use of forward-looking words such as ‘‘anticipate,’’ ‘‘believe,’’ ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among others.

Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters, including expected 2020 and/or 2021 production growth and capital expenditures plan. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors.

Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see filings with the U.S. Securities and Exchange Commission.

Oil and gas production figures included in this release are stated before the effect of royalties paid in kind, consumption and losses.

For further information, please contact:

INVESTORS:
Stacy Steimel – Shareholder Value Director
Santiago, Chile
T: +562 2242 9600
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Miguel Bello – Market Access Director
Santiago, Chile
T: +562 2242 9600
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MEDIA:
Communications Department
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NEW YORK--(BUSINESS WIRE)--International Seaways, Inc. (NYSE: INSW) (the “Company” or “INSW”), one of the largest tanker companies worldwide providing energy transportation services for crude oil and petroleum products in International Flag markets, today announced that its two joint ventures with Euronav NV have signed 10-year contract extensions with North Oil Company (NOC), the operator of the Al-Shaheen oil field, whose shareholders are Qatar Petroleum Oil & Gas Limited and Total E&P Golfe Limited. The contract extensions are for the FSO Asia and the FSO Africa and provide direct continuation of the current contractual service until July 21, 2032 and September 21, 2032 respectively.

The FSO Asia and FSO Africa, two high specification custom-built, three million barrel capacity floating storage offshore units, have been serving the Al-Shaheen oil field continuously since 2010.

The contract extensions are expected to generate in excess of $645 million in contract revenues for the joint ventures from the extension dates in 2022. Based on International Seaways’ ownership in the joint ventures, the 10-year contract extensions are expected to generate in excess of $322 million in contract revenues for the Company.

“We look forward to continue to partner with Euronav and support NOC’s offshore business and specifically its operations in the Al-Shaheen oil fields,” said Lois K. Zabrocky, International Seaways’ President and CEO. “The 10-year contract extensions underscore the commercial importance of these high specification vessels, positioning International Seaways to generate significant contracted revenue, as well as locking in the value of these important assets.”

About International Seaways, Inc.

International Seaways, Inc. (NYSE: INSW) is one of the largest tanker companies worldwide providing energy transportation services for crude oil and petroleum products in International Flag markets. International Seaways owns and operates a fleet of 39 vessels, including 13 VLCCs, two Suezmaxes, five Aframaxes/LR2s, 13 Panamaxes/LR1s and 4 MR tankers. Through joint ventures, it has ownership interests in two floating storage and offloading service vessels. International Seaways has an experienced team committed to the very best operating practices and the highest levels of customer service and operational efficiency. International Seaways is headquartered in New York City, NY. Additional information is available at https://www.intlseas.com.

Forward-Looking Statements

This release contains forward-looking statements. In addition, the Company may make or approve certain statements in future filings with the Securities and Exchange Commission (SEC), in press releases, or in oral or written presentations by representatives of the Company. All statements other than statements of historical facts should be considered forward-looking statements. These matters or statements may relate to the Company’s plans to issue dividends, its prospects, including statements regarding vessel acquisitions, trends in the tanker markets, and possibilities of strategic alliances and investments. Forward-looking statements are based on the Company’s current plans, estimates and projections, and are subject to change based on a number of factors. Investors should carefully consider the risk factors outlined in more detail in the Annual Report on Form 10-K for 2019 for the Company, the Quarterly Report on Form 10-Q for the quarters ended March 31, 2020 and June 30, 2020, and in similar sections of other filings made by the Company with the SEC from time to time. The Company assumes no obligation to update or revise any forward-looking statements. Forward-looking statements and written and oral forward-looking statements attributable to the Company or its representatives after the date of this release are qualified in their entirety by the cautionary statements contained in this paragraph and in other reports previously or hereafter filed by the Company with the SEC.

Investor Relations & Media Contact:
David Siever, International Seaways, Inc.
(212) 578-1635
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Self-Funded and Flexible Work Program with Low-Cost Production Growth, Development of the High-Potential CPO-5 Block and Returning Value to Shareholders

BOGOTA, Colombia--(BUSINESS WIRE)--GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Peru, Argentina, Brazil, Chile and Ecuador, today announced its work program and investment guidelines for 2021. (All figures are expressed in US Dollars).

A conference call to discuss third quarter 2020 financial results and the 2021 work program and investment guidelines will be held on November 5, 2020 at 10:00 a.m. Eastern Standard Time.

2021 Work Program: Main Principles and Approach

GeoPark has approved a self-funded and risk-balanced 2021 work program aimed at providing tangible value to its shareholders through value returns and the continuing development of its unique low-cost, low-risk project portfolio, considering the following principles:

Technical

• Efficient development of the Llanos 34 block (GeoPark operated, 45% WI)
• Accelerate development & exploration activities in the CPO-5 block (GeoPark non-operated, 30% WI)
• Define new plays, leads and prospects on its seven million acreage land position in ten basins
• Initiate exploration studies and drilling in GeoPark’s large, low-risk Llanos basin exploration acreage
• Start-up activities in Ecuador to initiate drilling in 2H2021 or early 2022
• Enhance base production levels in Chile, Argentina and Brazil

Economic

• Allocate investment capital to best shareholder value-adding projects determined on four key criteria: technical upside, strategic value, economic return and social and environmental impact
• Proven flexible capital expenditure program fully funded within cashflow
• Ongoing cost reduction efforts to further improve GeoPark’s leading cost efficiencies
• Preserve balance sheet strength with tools and safety nets in place
• Maximize net asset value per share
• Continue returning value to shareholders

Strategic

• Proven flexible program, adaptable to lower oil price scenarios
• Develop and add new short-cycle projects with low breakevens
• Grow strategic partnerships with Ecopetrol/Hocol, ONGC and Boru Energy
• Promote innovation and the adoption of best practices across the portfolio

Environmental, Social and Governance

• Maintain protocols and crisis response plans to keep people working safely and production flowing with teams reduced to minimum and back up teams in place
• Strengthen ESG+ metrics with GeoPark’s proven internal SPEED program
• Continue building strong relationships with neighbors and communities
• Partner with the United Nations Development Program (UNPD) to reduce social inequality in areas of influence
• Grid connection and renewable projects in the Llanos 34 block to further reduce carbon footprint expected to be operational by 2022

2021 Guidance ($40-45/bbl Brent)

The 2021 production guidance reflects average production of 40,000-42,000 boepd, excluding the potential production from the 2021 exploration drilling program.

The 2021 work program of $100-120 million includes drilling of 31-34 gross wells, with approximately 65% to be allocated to development activities and 35% to exploration activities.

Using the base case price assumption of $40-45/bbl Brent, GeoPark can execute a risk-balanced work program to continue growing its business by producing, developing and exploring its portfolio of assets, fully funded within cashflow, maintaining a strong balance sheet and returning value to its shareholders.

The 2021 work program reflects further improvements to the Company’s leading costs efficiencies with an operating netback to capital expenditures ratio of 2+ times and an operating netback to development capital of 3.5+ with Brent at $40-45 per bbl.

The table below provides the main highlights of the 2021 work program:

2021 Work Program Details

• Production target: 40,000-42,000 boepd average production
• Capital expenditure program: $100-120 million fully funded by cashflow, to be allocated as follows:
  • Colombia - $95-115 million: Focus on developing the Llanos 34 block, accelerating development of the CPO-5 block and acquiring seismic and delineating prospects in the Llanos and Putumayo exploration blocks.
    
    The work program in Colombia includes:
    - Llanos 34 block: 23-25 development and appraisal wells plus facilities to continue optimizing operating and transportation costs
    - CPO-5 block: 5-6 wells (2 development and appraisal and 3-4 exploration wells plus 3D seismic)
    - Llanos 94 block (GeoPark non-operated, 50% WI): one exploration well
    - Llanos 32 block (GeoPark non-operated, 12.5% WI): one appraisal and one exploration well
    - Seismic acquisition, reprocessing and other preliminary and preoperational activities in exploration blocks in the Llanos and Putumayo basins

• Ecuador - $4-5 million: 3D seismic and other preliminary activities to prepare for drilling in the Espejo (GeoPark operated, 50% WI) and Perico (GeoPark non-operated, 50% WI) blocks in 2H2021 or early 2022
• Chile, Argentina and Brazil - $1-2 million: Well intervention activities and facilities to enhance base production levels

Value Returns to Shareholders: Cash Dividends and Share Buyback Program

As part of the Company’s commitment to return value to its shareholders, today GeoPark’s Board of Directors declared an extraordinary and a quarterly cash dividend for 2020 and a share buyback program, as follows:

• 2020 Extraordinary Cash Dividend of $0.0206 per share ($1.25 million) payable on December 9, 2020
• 2020 Quarterly Dividend of $0.0206 per share ($1.25 million) payable on December 9, 2020
• Share Buyback Program to repurchase up to 10% of shares outstanding beginning on November 5, 2020 and expiring on November 15, 2021

For further details, please refer to the separate release published today.

Work Program Flexible at Different Oil Price Scenarios

Consistent with the Company’s approach in prior years, GeoPark’s 2021 work program can be rapidly adapted to different oil price scenarios, illustrating the high quality of its assets, its low-break-even production and strong financial performance in lower and volatile oil price environments.

• Above $50/bbl Brent oil price: Capital expenditures can be expanded to $140-160 million – by adding incremental projects, targeting average production of 42,000-44,000 boepd
• Below $35/bbl Brent oil price: Capital expenditures can be reduced to $50-85 million – focusing on the lowest-risk projects that produce the fastest cashflow, targeting average production of 38,000-40,000 boepd

GeoPark currently has commodity risk management contracts in place covering a portion of its production for 2021. GeoPark monitors market conditions on a continuous basis and expects to enter into additional new commodity risk management contracts to secure minimum oil prices for its 2021 production and beyond.

CONFERENCE CALL INFORMATION

GeoPark management will host a conference call on November 5, 2020 at 10:00 am (Eastern Standard Time) to discuss the 3Q2020 results and the work program and investment guidelines for 2021.

To listen to the call, participants can access the webcast located in the Investor Support section of the Company’s website at www.geo-park.com, or by clicking below:

https://event.on24.com/wcc/r/2770543/D46DCDE802A42ABE385B37543F22E6FC

Interested parties may participate in the conference call by dialing the numbers provided below:

United States Participants: 866-547-1509
International Participants: +1 920-663-6208
Passcode: 2754509

Please allow extra time prior to the call to visit the website and download any streaming media software that might be required to listen to the webcast. An archive of the webcast replay will be made available in the Investor Support section of the Company’s website at www.geo-park.com after the conclusion of the live call.

GLOSSARY

NOTICE

Additional information about GeoPark can be found in the “Investor Support” section on the website at www.geo-park.com.

Rounding amounts and percentages: Certain amounts and percentages included in this press release have been rounded for ease of presentation. Percentage figures included in this press release have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, certain percentage amounts in this press release may vary from those obtained by performing the same calculations using the figures in the financial statements. In addition, certain other amounts that appear in this press release may not sum due to rounding.

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

This press release contains statements that constitute forward-looking statements. Many of the forward-looking statements contained in this press release can be identified by the use of forward-looking words such as ‘‘anticipate,’’ ‘‘believe,’’ ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among others.

Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters, including expected 2020 and/or 2021 production growth, financial performance, oil prices and capital expenditures plan. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors.

Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see filings with the U.S. Securities and Exchange Commission.

Oil and gas production figures included in this release are stated before the effect of royalties paid in kind, consumption and losses.

INVESTORS:
Stacy Steimel – Shareholder Value Director
Santiago, Chile
T: +562 2242 9600
This email address is being protected from spambots. You need JavaScript enabled to view it.

Miguel Bello – Market Access Director
Santiago, Chile
T: +562 2242 9600
This email address is being protected from spambots. You need JavaScript enabled to view it.

MEDIA:
Communications Department
This email address is being protected from spambots. You need JavaScript enabled to view it.

GeoPark can be visited online at www.geo-park.com.

HOUSTON--(BUSINESS WIRE)--USD Partners LP (NYSE: USDP) (the “Partnership”) announced today its operating and financial results for the three and nine months ended September 30, 2020. Financial highlights with respect to the third quarter of 2020 include the following:

• Generated Net Cash Provided by Operating Activities of $16.6 million, Adjusted EBITDA⁽¹⁾ of $15.6 million and Distributable Cash Flow⁽¹⁾ of $13.6 million
• Reported Net Income of $6.2 million
• Declared a quarterly cash distribution of $0.111 per unit ($0.444 per unit on an annualized basis) with almost 4.5x Distributable Cash Flow Coverage

“We are pleased to report a successful third quarter for the Partnership,” said Dan Borgen, the Partnership’s Chief Executive Officer. “We continue to focus on optimizing our operations and increasing the strength of the Partnership’s liquidity position. Since reducing our distribution in the first quarter, the Partnership has paid down $19 million on its Revolver, which is trending higher than our previously-stated guidance to de-lever by approximately $20-$25 million on an annualized basis.”

“Also, we remain excited about our Sponsor’s previously announced diluent recovery unit (“DRU”) project, which is progressing on schedule. Our Sponsor has commenced construction on the project, as well as on the destination terminal in Port Arthur, Texas, and expects that both will be placed into service in the second quarter of 2021. In addition, all material regulatory permits and financing sources have been secured for the DRU and Port Arthur terminal. As a reminder, once the DRU and Port Arthur projects are complete, approximately 32% of the Partnership’s Hardisty terminal’s capacity will be automatically extended under a long-term committed agreement through mid-2031 with a strong investment grade customer. We look forward to keeping the market updated as things continue to develop, and especially with regards to our commercial discussions with other potential producer and refiner customers to secure long-term, take-or-pay agreements at the Partnership’s Hardisty terminal in support of future expansions of capacity at the DRU,” added Mr. Borgen.

Partnership’s Third Quarter 2020 Liquidity, Operational and Financial Results

Substantially all of the Partnership’s cash flows are generated from multi-year, take-or-pay terminalling services agreements related to its crude oil terminals, which include minimum monthly commitment fees. The Partnership’s customers include major integrated oil companies, refiners and marketers, the majority of which are investment-grade rated.

The Partnership’s operating results for the third quarter of 2020 relative to the same quarter in 2019 were primarily influenced by higher revenue at its Stroud terminal during the quarter due to higher rates that are based on crude oil index pricing differentials coupled with higher revenue at its Hardisty terminal associated with increased rates in some of the Partnership’s contracts. Lower revenue at the Partnership’s Casper terminal resulting from the conclusion of a customer agreement in August 2019 partially offset the higher revenue at Stroud and Hardisty during the quarter.

The Partnership experienced lower operating costs during the third quarter of 2020 as compared to the third quarter of 2019 due primarily to lower subcontracted rail services costs associated with lower throughput during the quarter and lower operating and maintenance costs associated with an agreement that the Partnership entered into in the third quarter of 2019 with the Hardisty South facility owned by the Partnership’s Sponsor to provide terminalling services for the contracted throughput that exceeded the Hardisty terminal’s transloading capacity. Under this arrangement, the Partnership incurred operating costs payable to the Partnership’s Sponsor representing the same rate, on a per barrel basis, that the Partnership received in revenue for such contracted throughput. The lower operating costs were partially offset by higher pipeline fees associated with the increased revenue at the Hardisty terminal.

Net income for the quarter increased as compared to the third quarter of 2019, primarily as a result of the operating factors discussed above coupled with lower interest expense incurred resulting from lower interest rates during the quarter and foreign currency transaction gains. This was partially offset by a higher non-cash loss associated with the Partnership’s interest rate derivative instrument.

In September 2020, the Partnership terminated its existing interest rate collar and simultaneously entered into a new interest rate swap that was made effective as of August 2020. The new interest rate swap is a five-year contract with a $150 million notional value that fixes the Partnership’s one-month LIBOR to 0.84% for the notional value of the swap agreement instead of the variable rate that the Partnership pays under its Credit Agreement. The swap settles monthly through the termination date in August 2025.

Net Cash Provided by Operating Activities for the quarter increased by 14% relative to the third quarter of 2019, primarily due to the operating factors discussed above and the general timing of receipts and payments of accounts receivable, accounts payable and deferred revenue balances.

Adjusted EBITDA and Distributable Cash Flow (“DCF”) increased by 12% and 29%, respectively, for the quarter relative to the third quarter of 2019. The increase in Adjusted EBITDA was primarily a result of the operating factors discussed above. DCF was also impacted by a decrease in cash paid for interest, income taxes and maintenance capital expenditures during the quarter.

As of September 30, 2020, the Partnership had approximately $7 million of unrestricted cash and cash equivalents and undrawn borrowing capacity of $176 million on its $385 million senior secured credit facility, subject to the Partnership’s continued compliance with financial covenants. Pursuant to the terms of the Partnership’s Credit Agreement, the Partnership’s borrowing capacity is currently limited to 4.5 times its trailing 12-month consolidated EBITDA, as defined in the Credit Agreement. As such, the Partnership’s available borrowings under the senior secured credit facility, including unrestricted cash and cash equivalents, was approximately $44 million as of September 30, 2020. The Partnership was in compliance with its financial covenants, as of September 30, 2020.

On October 22, 2020, the Partnership declared a quarterly cash distribution of $0.111 per unit ($0.444 per unit on an annualized basis), the same amount as distributed in the prior quarter. The distribution is payable on November 13, 2020, to unitholders of record at the close of business on November 3, 2020.

During the second and third quarters of 2020, the Partnership made net repayments of $6 million and $9 million, respectively, of the outstanding balance of its revolving credit facility. In addition, the Partnership has repaid an additional $4 million subsequent to the end of the third quarter of 2020.

Third Quarter 2020 Conference Call Information

The Partnership will host a conference call and webcast regarding third quarter 2020 results at 11:00 a.m. Eastern Time (10:00 a.m. Central Time) on Thursday, November 5, 2020.

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 7506289. 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 7506289. 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 (“USD”) 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.

USD, 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. USD 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 in the second 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 websites referenced in this release is not part of this release.

Non-GAAP Financial Measures

The Partnership defines Adjusted EBITDA as Net Cash Provided by Operating Activities adjusted for changes in working capital items, interest, income taxes, foreign currency transaction gains and losses, and other items which do not affect the underlying cash flows produced by the Partnership’s businesses. Adjusted EBITDA is a non-GAAP, supplemental financial measure used by management and external users of the Partnership’s financial statements, such as investors and commercial banks, to assess:

• the Partnership’s liquidity and the ability of the Partnership’s businesses to produce sufficient cash flows to make distributions to the Partnership’s unitholders; and
• the Partnership’s ability to incur and service debt and fund capital expenditures.

The Partnership defines Distributable Cash Flow, or DCF, as Adjusted EBITDA less net cash paid for interest, income taxes and maintenance capital expenditures. DCF does not reflect changes in working capital balances. DCF is a non-GAAP, supplemental financial measure used by management and by external users of the Partnership’s financial statements, such as investors and commercial banks, to assess:

• the amount of cash available for making distributions to the Partnership’s unitholders;
• the excess cash flow being retained for use in enhancing the Partnership’s existing business; and
• the sustainability of the Partnership’s current distribution rate per unit.

The Partnership believes that the presentation of Adjusted EBITDA and DCF in this press release provides information that enhances an investor's understanding of the Partnership’s ability to generate cash for payment of distributions and other purposes. The GAAP measure most directly comparable to Adjusted EBITDA and DCF is Net Cash Provided by Operating Activities. Adjusted EBITDA and DCF should not be considered alternatives to Net Cash Provided by Operating Activities or any other measure of liquidity presented in accordance with GAAP. Adjusted EBITDA and DCF exclude some, but not all, items that affect Net Cash Provided by Operating Activities and these measures may vary among other companies. As a result, Adjusted EBITDA and DCF may not be comparable to similarly titled measures of other companies. Reconciliations of Net Cash Provided by Operating Activities to Adjusted EBITDA and DCF are presented on page 10 of this press release.

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 ability of the Partnership and USD to achieve contract extensions, new customer agreements and expansions; the ability of the Partnership and USD to develop existing and future additional projects and expansion opportunities (including successful completion of USD’s DRU) and whether those projects and opportunities developed by USD would be made available for acquisition, or acquired, by the Partnership; volumes at, and demand for, the Partnership’s terminals; and the amount and timing of future distribution payments and distribution growth. Words and phrases such as “expect,” “plan,” “intent,” “believes,” “projects,” “begin,” “anticipates,” “subject to” 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 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. 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 the impact of the novel coronavirus (COVID-19) pandemic and related economic downturn and changes in general economic conditions and commodity prices, as well as those factors set forth under the heading “Risk Factors” and elsewhere in the Partnership’s most recent Annual Report on Form 10-K and in the Partnership’s subsequent filings with the Securities and Exchange Commission (many of which may be amplified by the COVID-19 pandemic and the recent significant reductions in demand for and prices of crude oil, natural gas and natural gas liquids). 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, except as required by law.

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