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DALLAS--(BUSINESS WIRE)--Pioneer Natural Resources Company (NYSE: PXD) ("Pioneer" or "the Company") today reported financial and operating results for the quarter ended September 30, 2020. Pioneer reported a third quarter net loss attributable to common stockholders of $20 million, or $0.12 per diluted share. These results include the effects of noncash mark-to-market adjustments and certain other unusual items. Excluding these items, non-GAAP adjusted income for the third quarter was $26 million, or $0.17 per diluted share. Cash flow from operating activities for the third quarter was $391 million.

Highlights

  • Delivered strong third quarter free cash flow1 of $131 million
  • Averaged third quarter oil production of 201 thousand barrels of oil per day (MBOPD), at the top end of guidance
  • Averaged third quarter production of 355 thousand barrels of oil equivalent per day (MBOEPD), near the top end of guidance
  • Reported capital expenditures2 of $291 million during the third quarter
  • Announced definitive agreement to acquire Parsley Energy, Inc. (Parsley)

President and CEO Scott D. Sheffield stated, "Pioneer continues to execute at a high level and delivered another strong quarter, generating $131 million of free cash flow1. For the second consecutive quarter, Pioneer increased our 2020 production guidance while keeping capital guidance unchanged, driven by strong operational efficiencies and cost reduction efforts. We continue to improve cash margins, with controllable cash costs being reduced by 25% this year when compared to 2019. Pioneer’s investment framework will be further strengthened in 2021 through our pending acquisition of Parsley Energy. We expect this highly accretive transaction to reduce our reinvestment rate to a range of 65% to 75%, allowing for significant free cash flow generation while maintaining a strong balance sheet. We believe these factors, in addition to our maintenance capital breakeven WTI oil price being in the low thirties, which includes coverage of the base dividend, position Pioneer as the premier independent energy investment."

Financial Highlights

Pioneer maintains a strong balance sheet, with unrestricted cash on hand at the end of the third quarter of $1.3 billion and net debt of $2.0 billion. The Company had $2.8 billion of liquidity as of September 30, 2020, comprised of $1.3 billion of unrestricted cash and a $1.5 billion unsecured credit facility (undrawn as of September 30, 2020).

During the third quarter, the Company’s drilling, completion and facilities capital expenditures totaled $277 million. The Company’s total capital expenditures2, including water infrastructure, totaled $291 million.

Cash flow from operating activities during the third quarter was $391 million, leading to free cash flow1 of $131 million for the quarter.

Financial Results

For the third quarter, the average realized price for oil was $39.22 per barrel. The average realized price for natural gas liquids (NGLs) was $16.93 per barrel, and the average realized price for gas was $1.74 per thousand cubic feet. These prices exclude the effects of derivatives.

Production costs, including taxes, averaged $6.89 per barrel of oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $12.04 per BOE. Exploration and abandonment costs were $16 million. General and administrative (G&A) expense was $64 million. Interest expense was $34 million. The net cash flow impact related to purchases and sales of oil and gas, including firm transportation, was a loss of $63 million. Other expense was $98 million, or $9 million excluding unusual items3.

Operations Update

Pioneer continued to see strong efficiency gains during the third quarter, enabling the Company to place 37 horizontal wells on production despite lower activity levels earlier in the year. During the first nine months of 2020, drilling operations averaged approximately 1,150 drilled feet per day and completion operations averaged approximately 1,800 completed feet per day, surpassing our strong results for the six months ended June 30, 2020. Pioneer's well costs continue to benefit from these efficiency gains, leading to additional cost reductions during the quarter of approximately $250 thousand per well, or a reduction of approximately $2 million per well when compared to the Company's original 2020 budget. The trend of lower well costs continues to significantly improve capital efficiency. Pioneer expects approximately 60% of the achieved well cost savings this year to be sustainable through commodity price cycles.

The Company's controllable cash costs, inclusive of lease operating expense, G&A and interest expense, continue to trend lower and represent an approximately 25% reduction per BOE in 2020 when compared to 2019. Pioneer's improved cost structure continues to drive strong margins and provide incremental cash flow. Cash flow is forecasted to improve even further once the pending acquisition of Parsley is completed, and the Company begins to realize the expected annual synergies associated with the acquisition of approximately $325 million.

The Company continues to proactively curtail lower-margin, higher-cost vertical well production in the current commodity price environment, benefiting operating costs. Pioneer curtailed approximately 5.5 MBOPD of net production during the third quarter and expects the same amount to remain curtailed in the current commodity price environment. The majority of the vertical wells associated with this production are expected to be plugged and abandoned and are not expected to return to production. Decisions to curtail production are economically driven and evaluated on a well-by-well basis.

Full-Year 2020 Update

The Company is maintaining its 2020 drilling, completions and facilities capital budget range of $1.3 billion to $1.5 billion, with an additional approximately $100 million budgeted for Pioneer's differentiated water infrastructure, resulting in a total 2020 capital budget2 range of $1.4 billion to $1.6 billion.

Pioneer is increasing its guidance for 2020 oil production to a range of 209 to 211 MBOPD and total production range of 365 to 369 MBOEPD. The Company continues to monitor the fluid macroeconomic environment and will remain flexible and responsive to changing market conditions to preserve its strong balance sheet.

The Company is currently operating eight horizontal drilling rigs and four frac fleets. The operated drilling rigs include one horizontal drilling rig in the southern joint venture area and one horizontal drilling rig associated with Pioneer's nine-well DrillCo agreement in the southern joint venture area. Pioneer will continue to evaluate its drilling and completions program on an economic basis, with future activity levels assessed regularly and governed by its reinvestment framework.

Pioneer has redefined its investment proposition to prioritize free cash flow generation and return of capital. This capital allocation framework is intended to create long-term value for shareholders by optimizing the reinvestment of cash flow to accelerate the Company's free cash flow profile. The acquisition of Parsley is expected to reduce the reinvestment rate from a range of 70% to 80% to a range of 65% to 75%, enhancing the value proposition for shareholders through increased free cash flow generation. Pioneer is targeting a 10% total annual return, inclusive of a strong and growing base dividend4, a variable dividend4 and high-return oil growth. The Company believes this differentiated strategy will position Pioneer to be competitive across sectors.

Pioneer continues to maintain substantial oil derivative coverage in order to protect the balance sheet, providing the Company with operational and financial flexibility. The Company’s financial and derivative mark-to-market results and open derivatives positions are outlined in the attached schedules.

Fourth Quarter 2020 Guidance

Fourth quarter 2020 oil production is forecasted to average between 197 to 207 MBOPD and total production is expected to average between 355 to 370 MBOEPD. Production costs are expected to average $6.25 per BOE to $7.75 per BOE. DD&A expense is expected to average $11.75 per BOE to $13.75 per BOE. Total exploration and abandonment expense is forecasted to be $5 million to $15 million. G&A expense is expected to be $56 million to $66 million. Interest expense is expected to be $35 million to $40 million. Other expense is forecasted to be $20 million to $30 million, excluding stacked drilling rig fees, idle frac fleet fees and other fees associated with reduced activity levels. Accretion of discount on asset retirement obligations is expected to be $2 million to $5 million. The cash flow impact related to purchases and sales of oil and gas, including firm transportation, is expected to be a loss of $40 million to $80 million, based on forward oil price estimates for the quarter. The Company’s effective income tax rate is expected to be less than 21%. Cash income taxes are expected to be nominal.

Environmental, Social & Governance

Pioneer views sustainability as a multidisciplinary focus that balances economic growth, environmental stewardship and social responsibility. The Company emphasizes developing natural resources in a manner that protects surrounding communities and preserves the environment.

Pioneer is focused on reducing emissions and emission intensities. Between 2016 and 2018, the Company's greenhouse gas (GHG) emissions have been reduced by 24%, total GHG emission intensity has decreased by 38% and methane intensity has declined by 41%. Additionally, between January 2018 and July 2019, the Company was able to limit Permian flaring to less than 2% of its produced gas, one of the lowest flaring percentages in the Permian Basin. The Company's proactive measures, including monitoring 100% of its Permian facilities aerially for leak detection and repair and only producing a well once it is fully connected to a gas line, help to make Pioneer a leader in environmental stewardship.

Socially, Pioneer maintains a proactive safety culture, supports a diverse workforce and inspires teamwork to drive innovation. The Board of Directors has a Health, Safety and Environment Committee and a Nominating and Corporate Governance Committee to provide director-level oversight of these activities. These committees help to promote a culture of continuous improvement in safety and environmental practices.

For more details, see Pioneer’s 2019 Sustainability Report at pxd.com/sustainability. Pioneer expects to publish its comprehensive 2020 Sustainability Report during the fourth quarter.

Earnings Conference Call

On Thursday, November 5, 2020, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 30, 2020, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.

Internet: www.pxd.com
Select "Investors," then "Earnings & Webcasts" to listen to the discussion, view the presentation and see other related material.

Telephone: Dial (800) 353-6461 and enter confirmation code 6756515 five minutes before the call.

A replay of the webcast will be archived on Pioneer’s website. This replay will be available through December 1, 2020. Click here to register for the call-in audio replay and you will receive the dial-in information.

Pioneer is a large independent oil and gas exploration and production company, headquartered in Dallas, Texas, with operations in the United States. For more information, visit www.pxd.com.

Additional Information and Where to Find It

This communication may be deemed to be solicitation material in respect of the proposed transaction. The proposed transaction will be submitted to Pioneer’s stockholders and Parsley’s stockholders for their consideration. Pioneer and Parsley intend to file a joint proxy statement/prospectus (the “Joint Proxy Statement/Prospectus”) with the SEC in connection with the solicitation of proxies by Pioneer and Parsley in connection with the proposed transaction. Pioneer intends to file a registration statement on Form S-4 (the “Form S-4”) with the SEC, in which the Joint Proxy Statement/Prospectus will be included. Pioneer and Parsley also intend to file other relevant documents with the SEC regarding the proposed transaction. The definitive Joint Proxy Statement/Prospectus will be mailed to Pioneer’s stockholders and Parsley’s stockholders when available. BEFORE MAKING ANY VOTING OR INVESTMENT DECISION WITH RESPECT TO THE PROPOSED TRANSACTION, INVESTORS AND STOCKHOLDERS OF PIONEER AND INVESTORS AND STOCKHOLDERS OF PARSLEY ARE URGED TO READ THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE PROPOSED TRANSACTION (INCLUDING ANY AMENDMENTS OR SUPPLEMENTS THERETO) AND OTHER RELEVANT MATERIALS CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION.

The Joint Proxy Statement/Prospectus, any amendments or supplements thereto and other relevant materials, and any other documents filed by Pioneer or Parsley with the SEC, may be obtained once such documents are filed with the SEC free of charge at the SEC’s website at www.sec.gov or free of charge from Pioneer at www.pxd.com or by directing a request to Pioneer’s Investor Relations Department at This email address is being protected from spambots. You need JavaScript enabled to view it. or free of charge from Parsley at www.parsleyenergy.com or by directing a request to Parsley’s Investor Relations Department at This email address is being protected from spambots. You need JavaScript enabled to view it..

No Offer or Solicitation

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities, or a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act.

Participants in the Solicitation

Pioneer, Parsley and certain of their respective executive officers, directors, other members of management and employees may, under the rules of the SEC, be deemed to be “participants” in the solicitation of proxies in connection with the proposed transaction. Information regarding Pioneer’s directors and executive officers is available in its Proxy Statement on Schedule 14A for its 2020 Annual Meeting of Stockholders, filed with the SEC on April 9, 2020 and in its Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 24, 2020. Information regarding Parsley’s directors and executive officers is available in its Proxy Statement on Schedule 14A for its 2020 Annual Meeting of Stockholders, filed with the SEC on April 6, 2020 and in its Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020. These documents may be obtained free of charge from the sources indicated above. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the Form S-4, the Joint Proxy Statement/Prospectus and other relevant materials relating to the proposed transaction to be filed with the SEC when they become available. Stockholders and other investors should read the Joint Proxy Statement/Prospectus carefully when it becomes available before making any voting or investment decisions.

Cautionary Statement Regarding Forward-Looking Information

Except for historical information contained herein, the statements in this news release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer’s actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand; the impact of a widespread outbreak of an illness, such as the COVID-19 pandemic, on global and U.S. economic activity; competition; the ability to obtain environmental and other permits and the timing thereof; other government regulation or action; the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms; litigation; the costs and results of drilling and operations; availability of equipment, services, resources and personnel required to perform the Company’s drilling and operating activities; access to and availability of transportation, processing, fractionation, refining, storage and export facilities; Pioneer's ability to replace reserves; implement its business plans or complete its development activities as scheduled; access to and cost of capital; the financial strength of counterparties to Pioneer's credit facility, investment instruments and derivative contracts and purchasers of Pioneer's oil, natural gas liquids and gas production; uncertainties about estimates of reserves and resource potential; identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying forecasts, including forecasts of production, cash flow, well costs, capital expenditures, rates of return, expenses, cash flow from purchases and sales of oil and gas, net of firm transportation commitments; sources of funding; tax rates; quality of technical data; environmental and weather risks, including the possible impacts of climate change; cybersecurity risks; ability to implement stock repurchases; the risks associated with the ownership and operation of the Company's oilfield services businesses and acts of war or terrorism. These and other risks are described in Pioneer's Annual Report on Form 10-K for the year ended December 31, 2019, Quarterly Reports on Form 10-Q filed thereafter and other filings with the United States Securities and Exchange Commission. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it.

Additionally, the information in this Report contains forward-looking statements related to the recently announced merger transaction between the Company and Parsley. Such forward-looking statements are subject to risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control. These risks and uncertainties include, among other things, the risk that the businesses of Pioneer and Parsley will not be integrated successfully; the cost savings, synergies and growth from the proposed transaction may not be fully realized or may take longer to realize than expected; management time may be diverted on transaction-related issues; the potential adverse effect of future regulatory or legislative actions on Pioneer and Parsley or the industries in which they operate, including the risk of new restrictions with respect to development activities on Pioneer's or Parsley's assets; the credit ratings of the combined company or its subsidiaries may be different from what Pioneer expects; Pioneer or Parsley may be unable to obtain governmental and regulatory approvals required for the proposed transaction, or that required governmental and regulatory approvals may delay the proposed transaction or result in the imposition of conditions that could reduce the anticipated benefits from the proposed transaction or cause the parties to abandon the proposed transaction; a condition to closing of the proposed transaction may not be satisfied; the length of time necessary to consummate the proposed transaction may be longer than anticipated for various reasons; potential liability resulting from pending or future litigation related to the proposed transaction; the potential impact of the announcement or consummation of the proposed transaction on relationships with customers, suppliers, and competitors; and transaction costs may be higher than anticipated.

Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. Pioneer undertakes no duty to publicly update these statements except as required by law.

Footnote 1: Free cash flow is a non-GAAP measure. See reconciliation to comparable GAAP number in supplemental schedules.

Footnote 2: Excludes acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A, information technology and corporate facilities.

Footnote 3: Unusual items include the following: (i) $74 million of employee-related charges associated with the Company's 2020 corporate restructuring and (ii) COVID-19 operational plan changes that led to (a) $14 million in charges related to idle frac fleet fees, stacked drilling rig charges and drilling rig early termination charges and (b) $1 million in sand take-or-pay deficiencies and other payments. See reconciliation in supplemental schedules.

Footnote 4: The declaration and payment of future dividends is at the discretion of the Company's Board of Directors and will depend on, among other things, the Company's earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the Board of Directors deems relevant.

 

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)

 

 

September 30, 2020

 

December 31, 2019

ASSETS

Current assets:

 

 

 

Cash and cash equivalents

$

1,325

 

 

$

631

 

Restricted cash

66

 

 

74

 

Accounts receivable, net

662

 

 

1,035

 

Income taxes receivable

22

 

 

7

 

Inventories

191

 

 

205

 

Derivatives

49

 

 

32

 

Investment in affiliate

67

 

 

187

 

Other

38

 

 

20

 

Total current assets

2,420

 

 

2,191

 

Oil and gas properties, successful efforts method of accounting

24,070

 

 

23,028

 

Accumulated depletion, depreciation and amortization

(9,719)

 

 

(8,583)

 

Total oil and gas properties, net

14,351

 

 

14,445

 

Other property and equipment, net

1,603

 

 

1,632

 

Operating lease right of use assets

198

 

 

280

 

Goodwill

261

 

 

261

 

Other assets

144

 

 

258

 

 

$

18,977

 

 

$

19,067

 

 

 

 

 

LIABILITIES AND EQUITY

Current liabilities:

 

 

 

Accounts payable

$

1,008

 

 

$

1,411

 

Interest payable

17

 

 

53

 

Income taxes payable

2

 

 

3

 

Current portion of long-term debt

140

 

 

450

 

Derivatives

51

 

 

12

 

Operating leases

99

 

 

136

 

Other

371

 

 

431

 

Total current liabilities

1,688

 

 

2,496

 

Long-term debt

3,148

 

 

1,839

 

Derivatives

14

 

 

8

 

Deferred income taxes

1,406

 

 

1,389

 

Operating leases

113

 

 

170

 

Other liabilities

954

 

 

1,046

 

Equity

11,654

 

 

12,119

 

 

$

18,977

 

 

$

19,067

 

 

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

2020

 

2019

 

2020

 

2019

Revenues and other income:

 

 

 

 

 

 

 

Oil and gas

$

922

 

 

$

1,235

 

 

$

2,617

 

 

$

3,567

 

Sales of purchased oil and gas

935

 

 

1,171

 

 

2,391

 

 

3,463

 

Interest and other income (loss), net

13

 

 

(222)

 

 

(145)

 

 

(42)

 

Derivative gain (loss), net

(57)

 

 

121

 

 

60

 

 

150

 

Gain (loss) on disposition of assets, net

2

 

 

20

 

 

7

 

 

(477)

 

 

1,815

 

 

2,325

 

 

4,930

 

 

6,661

 

Costs and expenses:

 

 

 

 

 

 

 

Oil and gas production

163

 

 

227

 

 

506

 

 

667

 

Production and ad valorem taxes

63

 

 

86

 

 

182

 

 

223

 

Depletion, depreciation and amortization

393

 

 

438

 

 

1,243

 

 

1,271

 

Purchased oil and gas

998

 

 

1,125

 

 

2,598

 

 

3,184

 

Exploration and abandonments

16

 

 

11

 

 

35

 

 

46

 

General and administrative

64

 

 

72

 

 

180

 

 

246

 

Accretion of discount on asset retirement obligations

2

 

 

2

 

 

7

 

 

7

 

Interest

34

 

 

29

 

 

94

 

 

88

 

Other

98

 

 

32

 

 

273

 

 

390

 

 

1,831

 

 

2,022

 

 

5,118

 

 

6,122

 

Income (loss) before income taxes

(16)

 

 

303

 

 

(188)

 

 

539

 

Income tax benefit (provision)

(4)

 

 

(72)

 

 

18

 

 

(127)

 

Net income (loss) attributable to common stockholders

$

(20)

 

 

$

231

 

 

$

(170)

 

 

$

412

 

 

 

 

 

 

 

 

 

Basic and diluted net income (loss) per share attributable to common
stockholders

$

(0.12)

 

 

$

1.38

 

 

$

(1.03)

 

 

$

2.44

 

 

 

 

 

 

 

 

 

Basic and diluted weighted average shares outstanding

165

 

 

167

 

 

165

 

 

168

 


Contacts

Pioneer Natural Resources Company Contacts:
Investors
Neal Shah - 972-969-3900
Tom Fitter - 972-969-1821
Michael McNamara - 972-969-3592
Greg Wright - 972-969-1770

Media and Public Affairs
Tadd Owens - 972-969-5760


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TORONTO--(BUSINESS WIRE)--Sherritt International Corporation (“Sherritt”, the “Corporation”, the “Company”) (TSX: S), a world leader in the mining and hydrometallurgical refining of nickel and cobalt from lateritic ores, today reported its financial results for the three- and nine-month periods ended September 30, 2020. All amounts are in Canadian currency unless otherwise noted.

During the quarter, pursuant to its plan of arrangement under the Canadian Business Corporations Act, Sherritt announced the successful closing of the latest step in its program to improve its capital structure. Overall, the transaction which closed on August 31, represented completion of the key Ambatovy part in the broader restructuring of Sherritt’s debt obligations.

In summary, this CBCA restructuring:

  • eliminated a further $300 million in direct debt;
  • eliminated debt maturities in 2021, 2023, and 2025, and replaced them with maturities in 2026 and 2029;
  • reduced our cash interest expense by one-third to approximately $30 million per year;
  • completed our exit from the Ambatovy project, eliminating the associated direct and indirect debt and the risk of being required to fund further cash calls with the associated risk of default; and
  • achieved all of this with no dilution to the current equity of Sherritt.

CHAIRMAN COMMENTARY

Commenting on the debt restructuring program, Sherritt Chairman Sir Richard Lapthorne said, “Preserving adequate liquidity and rebuilding balance sheet strength have been Sherritt’s top priorities since the current management team and Board have been in place. This has been a step-by-step process requiring a sustained concentration on removing the threats to the Corporation’s viability, and this process had to focus on Ambatovy. Indeed, final resolution of our Ambatovy position was a key part of the recently completed CBCA arrangement.”

He continued, “Sherritt entered the Ambatovy project in 2007 as a 40% partner with Sumitomo and Kores, our Korean partner, through the $1.6 billion acquisition of Dynatec. At that time, the project was forecast to require funding of US$3.3 billion. A senior debt facility of US$2.1 billion with recourse to the three partners was negotiated with the balance to be funded directly by the partners. However, the capital requirement for Ambatovy grew and, at the last count, had reached US$8.5 billion of which the shareholders funded US$6.4 billion. A feature of the shareholder agreement was that each partner had to meet its calls for cash from the joint venture or risk a default, which could cross default to its other borrowings; in Sherritt’s case to its publicly traded debentures. As early as 2009, Sherritt was forced to start mortgaging its future earnings from the project by borrowing from the other partners in order to finance its cash calls. By 2016, with accrued compound interest, one of these loans had a balance of $1.4 billion with no direct recourse to Sherritt, whilst the other of $133 million became a liability on Sherritt’s consolidated balance sheet.”

Sir Richard added, “Over the past six year, the management team has worked tirelessly in seeking to reduce these financial risks created through its Ambatovy commitments. In 2015, a combination of specialists from Sherritt’s Technologies business and locally-based expatriate management enabled Ambatovy to operate its mine and plant at the required throughput relative to capacity to enable the senior loans to become without recourse to the partners’ own balance sheets. This removed US$840 million from Sherritt’s debt profile. In 2017, Sherritt negotiated with its partners to reduce its shareholding in Ambatovy to 12%. As a consequence, the partner loan of $1.4 billion was cancelled and Sherritt’s responsibility for meeting the JV’s total cash calls dropped from 40% to 12%. Finally, as part of the CBCA Court application completed in August 2020, the 12% stake was surrendered, the remaining partner loan, which had increased to $145 million on Sherritt’s Balance Sheet, was cancelled and the financial planning uncertainty created by its cash call and potential default exposures from Ambatovy was extinguished.

“Sherritt has also effectively addressed the non-Ambatovy components in its funding. In 2006 it had borrowed $274 million in publicly-traded debentures. Through the course of funding Ambatovy, total public debenture debt peaked at $1,158 million in 2013. Following the recently completed restructuring, debenture debt has now fallen to $358 million at the end of September 2020. Bondholders also hold a $75 million 2029 note. In 2014, Sherritt sold its coal business for $814 million of total cash proceeds. Not only was this a well-timed business decision, but it also assisted the Corporation’s liquidity planning. The cash proceeds were used to redeem $300 million of debentures with the balance ultimately sustaining Sherritt’s liquidity during the prolonged Ambatovy exit program.”

Sir Richard concluded by saying, “In total, since 2014, Sherritt has eliminated approximately $2.4 billion in debt from the balance sheet along with a further $1.1 billion debt guarantee, and has removed the default risks posed by the Ambatovy agreements. Had we failed to do these, Sherritt would not exist in its current form today.”

CEO COMMENTARY

“The completion of the balance sheet initiative and the resolution of the Ambatovy legacy debt puts Sherritt in the best possible position to manage our business through the long term,” said David Pathe, President and CEO of Sherritt. “We have achieved this outcome despite the significant volatility in nickel and cobalt pricing and the increasingly aggressive U.S. policy towards Cuba we have seen over the last few years.”

Mr. Pathe added, “With the debt restructuring now behind us, our near-term focus will centre on sustaining the momentum we have been able to establish at the Moa Joint Venture and achieve our production targets for 2020. That we are on track for this achievement is a testament to the determination and resiliency of so many Sherritt employees managing the impact of the COVID-19 pandemic.

“We continue to take proactive actions to manage our liquidity. Since the end of the quarter, we have received a US$15 million distribution from the Moa JV, representing both our 50% share of US$7.5 million and our Cuban partner’s share of US$7.5 million, which is being redirected towards overdue receivables pursuant to our 2019 receivables agreement. We have also taken advantage of the recent strength in nickel prices to purchase a derivative contract to provide a floor ­­- but no cap - on 25% of our share of 2021 nickel production at $6.50 per pound, which protects our 2021 cash flow against downside risk to the nickel price next year.

“Over the longer term, we anticipate demand for our products to grow given the strong outlook for nickel in the coming years, particularly as the market adoption of electric vehicles accelerates, and we will bring greater focus to the projects and innovation of our Technologies Group and look to commercialize those innovations to create new revenue streams for Sherritt.”­

SUMMARY OF KEY Q3 2020 DEVELOPMENTS

  • Sherritt successfully completed its balance sheet initiative, which improved its capital structure and addressed its Ambatovy investment legacy, following stakeholder approval. As a result of the transaction, Sherritt reduced its total outstanding debt by approximately $301 million, extended the maturities of its note obligations to 2026 and 2029, reduced cash annual interest payments by more than $15 million, and terminated its debt obligations relating to the Ambatovy Joint Venture, all without any dilution of its common shares.
  • Following close of its balance sheet initiative, Sherritt’s note obligations, totaling $433 million, were reclassified as long-term debt.
  • Sherritt’s share of finished nickel production at the Moa Joint Venture (Moa JV) in Q3 2020 was 3,750 tonnes, down 9% from last year, while finished cobalt was 409 tonnes, down 6% from last year. The decline was due to the rescheduling of the planned plant shutdown and maintenance activities at the refinery in Fort Saskatchewan from June to July as previously disclosed. The Moa JV remains on track to meet its production guidance in 2020 and has produced 23,466 tonnes of finished nickel and 2,468 tonnes of finished cobalt on a 100% basis through September 30.
  • Sherritt ended Q3 2020 with cash and cash equivalents of $165.1 million of which $82.1 million was held by Energas in Cuba. The $7.3 million decrease in Sherritt’s liquidity from $172.4 million at the end of Q2 2020 was largely driven by costs associated with the balance sheet initiative, including approximately $16 million of cash payments made to note holders as early consent consideration.
  • Net earnings from continuing operations totaled $11.4 million, or $0.03 per share, and included a non-cash gain of $143.4 million on the exchange of debentures relating to the balance sheet initiative, offset by a non-cash impairment loss of $115.6 million relating to the write down of Block 10 capital assets.
  • Sherritt recognized earnings from discontinued operations of $217.1 million related to the disposition of its 12% ownership interest in the Ambatovy Joint Venture as part of the balance sheet initiative and reclassification as discontinued operations.
  • Sherritt received US$16.3 million in Cuban energy payments as part of the overdue receivables agreement with its Cuban partners. Payments, which included US$14.0 million received in Canada and US$2.3 million accepted in Cuba to support local costs for Sherritt’s Oil and Gas operations, were lower than expected as the spread of COVID-19 and the ongoing impact of U.S. sanctions limited Cuba’s access to foreign currency in Q3 2020.
  • Sherritt completed the analysis on a second set of samples from Block 10 that confirmed that the water produced during the test period is from the loss circulation zone, which is located at a depth of approximately 5,300 meters and above the target oil reservoir. The analysis also confirmed that no viable technical solution to prevent the further flow of water into the existing well is possible. While Sherritt still believes that the Block 10 reservoir contains oil, the existing well cannot be used for future production purposes. Sherritt is currently reviewing its options with respect to Block 10, including seeking an earn-in partner. At this time, Sherritt is not contemplating any further investments in Block 10 without first securing an earn-in partner.
  • Sherritt released its 2019 Sustainability Report that showed progress against the Company’s Environmental, Social and Governance targets, including efforts to reduce greenhouse house emissions, maintain peer-leading safety metrics, and commit to doubling the number of female employees by 2030.

DEVELOPMENTS SUBSEQUENT TO THE QUARTER END

  • The Moa JV paid a US$15 million distribution to its shareholders in November. Sherritt received its 50% share of this distribution, or US$7.5 million, directly. In addition, General Nickel Company, Sherritt’s joint venture partner, re-directed its US$7.5 million share of this distribution to the Corporation to be applied against amounts owing to Sherritt from Energas. The re-direction was secured through negotiations between Sherritt and its Cuban partners, and was made in accordance with the June 2019 overdue receivables agreement.
  • Sherritt purchased put options on 25% of its share of attributable finished nickel production from the Moa JV for 2021 at a strike price of US$6.50/lb. Any cash settlements will be completed on a monthly basis against the average monthly nickel price on the London Metals Exchange and will involve no physical delivery. The hedging strategy, which will be in effect for a 12-month period starting January 1, 2021, is designed to provide Sherritt with cash flow security in 2021 against major downward changes in nickel prices.
  • Sherritt employee members of Unifor at the refinery in Fort Saskatchewan ratified a new collective agreement through March 31, 2022. The new agreement extends Sherritt’s track record of no labour disruptions at the refinery since it began operations in 1954.
  • Sherritt agreed to an extension for the maturity of its $70 million credit facility from its syndicate of lenders to December 31, 2020. A longer-term extension is expected to be finalized in Q4 2020.
  • Sherritt continues to be in discussion with its Spanish partners on a potential alternative arrangement relating to the expired $47.0 million letter of credit for reclamation costs associated with Sherritt’s Spanish oil assets.

(1)

 

For additional information see the Non-GAAP measures section of this press release.

Q3 2020 FINANCIAL HIGHLIGHTS(1)

 

For the three months ended

 

 

 

 

For the nine months ended

 

 

 

 

2020

 

 

2019

 

 

 

 

2020

 

 

2019

 

 

$ millions, except per share amount

September 30

 

September 30

 

Change

 

September 30

 

September 30

 

Change

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

24.9

 

27.6

 

(10

%)

$

91.6

 

$

105.3

 

(13

%)

Combined revenue(2)

 

115.3

 

133.7

 

(14

%)

 

(36.4

)

 

401.9

 

(109

%)

Net earnings (loss) from continuing operations for the period

 

11.4

 

(15.4

)

174

%

 

(36.4

)

 

(76.8

)

53

%

Net earnings (loss) for the period

 

228.5

 

(30.0

)

862

%

 

71.8

 

 

(182.2

)

139

%

Adjusted EBITDA(2)

 

15.5

 

20.9

 

(26

%)

 

28.2

 

 

28.5

 

(1

%)

Cash provided (used) by continuing operations

 

25.3

 

1.5

 

nm(3)

 

35.3

 

 

(18.2

)

294

%

Combined adjusted operating cash flow(2)

 

21.5

 

15.4

 

40

%

 

45.9

 

 

(2.7

)

nm(3)

Combined free cash flow(2)

 

27.1

 

(12.3

)

320

%

 

29.5

 

 

(52.3

)

156

%

Average exchange rate (CAD/US$)

 

1.332

 

1.320

 

-

 

 

1.354

 

 

1.329

 

-

 

Net earnings (loss) from continuing operations per share

 

0.03

 

(0.04

)

175

%

 

(0.09

)

 

(0.19

)

53

%

(1)

 

All non-GAAP measures exclude the Joint Venture performance. As a result of the transaction, Ambatovy Joint Venture’s share of loss of an associate and other statement of comprehensive income (loss) items related to the Ambatovy Joint Venture were reclassified to the loss on discontinued operations in the current and comparative periods. The loss on discontinued operations also includes the gain on disposal of Ambatovy Joint Venture Interests in the current period.

(2)

 

For additional information see the Non-GAAP measures section.

(3)

 

Not meaningful (nm)

2020

 

2019

 

 

$ millions, as at

September 30

 

December 31

 

Change

 

 

 

 

 

 

Cash, cash equivalents and short term investments

$

165.1

$

166.1

(1

%)

Loans and borrowings

 

440.7

 

713.6

(38

%)

Cash, cash equivalents and short-term investments at September 30, 2020 were $165.1 million, down from $172.4 million at June 30, 2020. The decrease was due to a number of factors including, cash payments of approximately $16 million made to noteholders as early consent consideration and capital expenditures totaling $2.5 million, partially offset by higher Cuban energy payments. In addition, interest payments owed to holders of Sherritt’s series of debentures maturing in 2021, 2023 and 2025 were deferred as a result of the balance sheet initiative. Upon close of the transaction, all unpaid and accrued interest amounts were added to the principal amounts of second lien notes exchanged to holders for old notes.

As at September 30, 2020, $82.1 million of Sherritt’s cash and cash equivalents was held by Energas in Cuba, down from $82.2 million at the end of Q2 2020.

Sherritt received US$16.3 million in Cuban energy payments as part of its overdue receivables agreement with its Cuban partners in Q3 2020. Payments, which included US$14.0 million received in Canada and US$2.3 million accepted in Cuba to support local costs relating to Sherritt’s Oil and Gas operations, were lower than expected as the spread of COVID-19 and the ongoing impact of U.S. sanctions limited Cuba’s access to foreign currency in Q3 2020. Total overdue scheduled receivables at September 30, 2020 were US$159.1 million, unchanged from June 30, 2020 due to the timing of payments received and scheduling of expected payments. Subsequent to September 30, 2020, the Corporation received US$2.6 million in Canada from the Cuban overdue receivables agreement and US$2.4 million in Cuba to support local costs.

In Q3 2020, the Moa JV declared dividends of US$15 million, which were subsequently distributed in Q4 2020. In addition to Sherritt receiving its US$7.5 million share of this distribution, General Nickel Company, the Corporation’s joint venture partner, re-directed its share of this distribution to Sherritt to be applied against amounts owing to Sherritt from Energas. This re-direction was secured through negotiations between Sherritt and its Cuban partners, and was made in accordance with the June 2019 overdue receivables agreement. Sherritt anticipates receiving further dividend distributions in Q4 2020 given prevailing nickel and cobalt prices.

Sherritt anticipates that its liquidity position through the end of 2020 will largely be dependent on its ability to collect on amounts owed to it by its Cuban energy partners and dividends received from the Moa JV.

Adjusted net loss(1)

 

 

2020

 

 

2019

For the three months ended September 30

$ millions

 

$/share

 

$ millions

 

$/share

 

 

 

 

 

 

 

 

 

Net earnings (loss) from continuing operations

 

11.4

 

 

0.03

 

 

(15.4

)

 

(0.04

)

 

 

 

 

 

 

 

 

 

Adjusting items:

 

 

 

 

 

 

 

 

Unrealized foreign exchange (gain) loss

 

(3.6

)

 

(0.01

)

 

(5.5

)

 

(0.01

)

Gain on debenture exchange

 

(143.4

)

 

(0.36

)

 

-

 

 

-

 

Impairment of Oil assets

 

115.6

 

 

0.29

 

 

-

 

 

-

 

Other

 

3.9

 

 

0.01

 

 

0.3

 

 

-

 

Adjusted net loss from continuing operations

 

(16.1

)

 

(0.04

)

 

(20.6

)

 

(0.05

)

 

 

2020

 

2019

For the nine months ended September 30

$ millions

$/share

$ millions

$/share

 

 

 

 

 

 

 

 

 

Net earnings (loss) from continuing operations

 

(36.4

)

 

(0.09

)

 

(76.8

)

 

(0.19

)

 

 

 

 

 

 

 

 

 

Adjusting items:

 

 

 

 

 

 

 

 

Unrealized foreign exchange (gain) loss

 

(8.7

)

 

(0.02

)

 

(0.8

)

 

-

 

Gain on debenture exchange

 

(143.4

)

 

(0.36

)

 

-

 

 

-

 

Moa JV expansion loans ACL revaluation

 

(6.4

)

 

(0.02

)

 

-

 

 

-

 

Impairment of Oil assets

 

115.6

 

 

0.29

 

 

-

 

 

-

 

Other

 

6.3

 

 

0.02

 

 

(1.2

)

 

(0.01

)

Adjusted net loss from continuing operations

 

(73.0

)

 

(0.18

)

 

(78.8

)

 

(0.20

)

(1)

 

For additional information see the Non-GAAP measures section.

Net earnings from continuing operations for Q3 2020 was $11.4 million, or $0.03 per share, compared to a net loss of $15.4 million, or $0.04 per share, for the same period last year. Net earnings for Q3 2020 includes a gain of $143.4 million on the exchange of debentures as part of the balance sheet initiative offset by an impairment loss recognized on the write down of exploration and evaluation assets and capitalized spare parts relating to Block 10 drilling activities totaling $115.6 million.

Adjusted net loss from continuing operations was $16.1 million, or $0.04 per share, for the three months ended September 30, 2020 compared to an adjusted net loss from continuing operations of $20.6 million, or $0.05 per share, for Q3 2019.

On the close of the balance sheet initiative, Sherritt exchanged its 12% ownership interest and its loans and operator fee receivables in the Ambatovy Joint Venture for $145.6 million owed to its partners. Consistent with IFRS standards, Sherritt’s investment in the Ambatovy Joint Venture met the criteria to be classified and presented as discontinued operations for accounting purposes. As a result, Sherritt’s share of loss of an associate, net of tax, and other components of comprehensive income (loss) related to the Ambatovy Joint Venture were reclassified to the earnings (loss) on discontinued operations, net of tax, in the current and comparative periods. Sherritt recognized earnings on the disposition and reclassification of $217.1 million in Q3 2020 as a result.

METALS MARKET

Nickel

Nickel market conditions continued to improve in the third quarter of 2020, sustaining the trend started in Q2 with the easing of lock-down restrictions related to the COVID-19 pandemic and the restart of economic and manufacturing activities, particularly in China.

Nickel prices on the London Metals Exchange (LME) opened at US$5.69/lb on July 1 and closed on September 30 at US$6.52/lb, representing a growth of 15%.

While nickel prices climbed during Q3, nickel inventory levels on the London Metals Exchange (LME) and the Shanghai Future Exchange (SHFE) remained relatively flat. Combined inventory levels at September 30 totaled approximately 263,000 tonnes, up from approximately 262,000 tonnes at June 30. Nickel inventories on the LME and SHFE have stayed relatively flat despite the reduced production of stainless steel globally on a year to date basis largely because a number of nickel mines around the world have either significantly reduced production or have gone into care and maintenance as a result of the spread of COVID-19. Production at the Moa JV has largely been unaffected by the spread of COVID-19 through September 30.

Renewed interest in electric vehicles and bullish forecasts for accelerated demand growth in the coming years have triggered speculative purchasing from commodity investors, sustaining the nickel price momentum into the fourth quarter. A number of carmakers, in particular, have indicated that high purity nickel will be the primary metal in their battery chemistries. At October 20, nickel prices had risen to US$7.16/lb, the highest price since the start of 2020. This renewed interest in nickel is expected to contribute to higher prices into 2021.

Over the medium term, nickel prices are expected to be volatile given the ongoing economic uncertainty caused by the pandemic. As mining operations resume production activities, nickel inventory levels may rise given that supply could exceed demand as a number of industries that are large consumers of stainless steel, such as food and hospitality sector, will experience a delayed or slower economic recovery, particularly if the second wave of the pandemic is prolonged.

In light of this uncertainty, a number of industry analysts have lowered their forecasts for nickel demand from end consumers, reflecting negative market sentiment through the end of 2021. Previously, demand for nickel through 2025 was expected to grow by approximately 3% per year to 2.8 million tonnes according to market research by Wood Mackenzie.

Added to this uncertainty is the substantial increase in nickel pig iron production, leading some industry analysts to predict an oversupplied nickel market in the near term. This development is putting additional pressure on producers of lower-grade material such as ferronickel, which is currently selling at significant discount. As a result, it remains unclear how nickel prices will fare in the near term.

Over the longer term, demand for nickel is expected to increase with the increased adoption of electric vehicles since nickel – along with cobalt – is a key metal needed to manufacture assorted energy storage batteries.

Cobalt

Cobalt prices experienced a turnaround in Q3 following an extended period of softness through much of the first half of the year as a result of the impact COVID-19 on consumer demand. Standard grade cobalt prices, in fact, rose 9% ending the quarter at US$15.65/lb according to data collected by Fastmarkets MB. Standard grade cobalt prices on July 1 closed at US$14.30/lb, widely believed by industry watchers and traders to be a floor-level price.

It is speculated that market conditions have improved for a number of factors, including growing demand from battery manufacturers as a result of higher demand for electronics and computer equipment due to the growing trend of working from home accelerated since the start of the COVID-19 pandemic.


Contacts

Joe Racanelli, Director of Investor Relations
Telephone: (416) 935-2457
Toll-free: 1 (800) 704-6698
E-mail: This email address is being protected from spambots. You need JavaScript enabled to view it.


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THE WOODLANDS, Texas--(BUSINESS WIRE)--Earthstone Energy, Inc. (NYSE: ESTE) (“Earthstone”, the “Company”, “we”, “our” or “us”), today announced financial and operating results for the three months ended September 30, 2020.


Third Quarter 2020 Highlights

  • Average daily production of 16,959 Boepd(1)
  • Adjusted EBITDAX(2) of $36.4 million ($23.33 per Boe)
  • All-in cash costs(2) of $9.18 per Boe
  • Operating Margin(2) of $20.07 per Boe ($25.54 including realized hedge settlements)
  • Operating portion of net cash received in settlement of derivative contracts of $8.5 million
  • Free Cash Flow(2) of $33.8 million
  • Capital expenditures of $1.4 million
  • Reduction of long-term debt of $38.6 million
  • Net loss of $(11.9) million, or $(0.18) per Adjusted Diluted Share(2)
    • Adjusted net income of $3.7 million, or $0.06 per Adjusted Diluted Share(2)

Year-to-Date 2020 Highlights

  • Average daily production of 15,433 Boepd(1)
  • Adjusted EBITDAX(2) of $114.4 million ($27.07 per Boe)
  • All-in cash costs(2) of $10.72 per Boe
  • Operating Margin(2) of $18.60 per Boe ($29.87 including realized hedge settlements)
  • Operating portion of net cash received in settlement of derivative contracts of $47.6 million
  • Free Cash Flow(2) of $63.8 million
  • Capital expenditures of $46.4 million
  • Reduction of long-term debt of $40.0 million
  • Net loss of $(11.1) million, or $(0.17) per Adjusted Diluted Share(2)
    • Adjusted net income of $24.2 million, or $0.37 per Adjusted Diluted Share(2)

(1) Represents reported sales volumes
(2) See "Non-GAAP Financial Measures" section below.

Management Comments

Mr. Robert J. Anderson, President and CEO of Earthstone, commented, “We produced outstanding operational and financial results in the third quarter, buoyed in particular by strong production volumes and our continued focus on managing operational and corporate costs. These results continue to validate our economic inventory and operating track record. For the third quarter, despite no drilling or completion activities, we managed to generate Adjusted EBITDAX of over $36 million, which is only a 5% decrease from the first quarter before the impact of COVID-19 on commodity prices had fully occurred. Further, we generated nearly $34 million in Free Cash Flow which allowed us to pay down over $38 million in debt. Since year-end 2019, we generated nearly $64 million in Free Cash Flow which allowed us to pay down debt by $40 million. All of this has contributed to our continued expectation that we will meet our target of being below 1x net debt to Adjusted EBITDAX at year-end.”

Mr. Anderson commented further, “With the strength of our production results, we are increasing our production guidance for full year 2020, largely comprised of higher natural gas and natural gas liquids volumes, with oil volumes approximately the same. We are also tightening our lease operating expense guidance, as we have been successful in driving down these costs.

Additionally, we have initiated completions on a six-well pad in Upton County based on the current forecast for oil prices, reduction in service costs and our expectation of significant production and economic results from this pad, which we expect to be online around year-end. We also anticipate completing the remaining five drilled but uncompleted wells in our inventory in the first quarter of 2021. This completion activity is expected to keep our production relatively flat in 2021, on a year over year basis, which would contribute to significant Free Cash Flow in 2021.”

Updated 2020 Guidance

The Company has updated its 2020 guidance based on activities to date and expected for the remainder of 2020 as shown below. The Company has increased its average daily production guidance and decreased its per unit lease operating expense guidance. Further, the Company is increasing its capital expenditure guidance for the year by $12.5 million at the midpoint, which reflects incremental expected fourth quarter 2020 expenditures of approximately $20 million for newly added well completion activities, but offset by lower year-to-date spending of approximately $7.5 million than anticipated.

2020 Capital Expenditures

$ millions

(Net)

Gross / Net

Operated

Wells Drilled & Awaiting

Completion

Gross / Net

Operated

Wells On Line

Net

Non-Operated

Wells On Line

Drilling and Completions

$60 – 65

5 / 3.7

9 / 9.0

3.1

Land / Infrastructure

5

 

 

 

2020 Total Capital Expenditures

$65 – 70

 

 

 

 

 

 

 

 

2020 Average Daily Production (Boepd)

14,000 – 14,500

 

 

 

% Oil

58% – 59%

 

 

 

% Liquids

79% – 80%

 

 

 

 

 

 

 

 

2020 Operating Costs

 

 

 

 

Lease Operating Expense ($/Boe)

$5.25 – $5.50

 

 

 

Production and Ad Valorem Taxes (% of Revenue)

6.25% – 7.25%

 

 

 

Cash G&A (1) ($mm)

$15.5 – $16.5

 

 

 

Note: Guidance is forward-looking information that is subject to considerable change and numerous risks and uncertainties, many of which are beyond Earthstone’s control. See “Forward-Looking Statements” section below.

(1)

Cash G&A is a non-GAAP measure defined as general and administrative expenses less stock-based compensation which is not settled in cash.

 

Operations Update

We have initiated completions on six drilled but uncompleted wells on our Ratliff project in Upton County (100% working interest). These six wells have an average lateral length of approximately 8,400 feet with laterals in the Wolfcamp A, Wolfcamp B Upper and Lower and Wolfcamp C. These four zones have all been successfully produced by us or offset operators in close proximity to this project. These wells are expected to be online by year-end 2020, but we do not anticipate any meaningful production contribution in 2020. We plan to begin completions activity of the remaining five drilled but uncompleted wells on the Hamman Upton project (75% working interest) in January 2021.

 

 

Selected Financial Data (unaudited)

($000s except where noted)

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

2020

 

2019

 

2020

 

2019

Total revenues

$

41,047

 

 

$

39,204

 

 

$

107,848

 

 

$

124,474

 

 

 

 

 

 

 

 

 

Lease operating expense

7,044

 

 

6,419

 

 

21,971

 

 

20,485

 

 

 

 

 

 

 

 

 

General and administrative expense (excluding stock-based compensation)

3,393

 

 

3,850

 

 

11,950

 

 

13,268

 

Stock-based compensation (non-cash)

2,403

 

 

2,207

 

 

7,665

 

 

6,680

 

General and administrative expense

$

5,796

 

 

$

6,057

 

 

$

19,615

 

 

$

19,948

 

 

 

 

 

 

 

 

 

Net (loss) income

$

(11,858

)

 

$

26,127

 

 

$

(11,053

)

 

$

7,220

 

Less: Net (loss) income attributable to noncontrolling interest

(6,413

)

 

14,357

 

 

(5,977

)

 

3,877

 

Net (loss) income attributable to Earthstone Energy, Inc.

(5,445

)

 

11,770

 

 

(5,076

)

 

3,343

 

Net (loss) income per common share(1)

 

 

 

 

 

 

 

Basic

(0.18

)

 

0.41

 

 

(0.17

)

 

0.12

 

Diluted

(0.18

)

 

0.41

 

 

(0.17

)

 

0.12

 

Adjusted EBITDAX(2)(5)

$

36,399

 

 

$

29,963

 

 

$

114,448

 

 

$

96,379

 

 

 

 

 

 

 

 

 

Production(3):

 

 

 

 

 

 

 

Oil (MBbls)

839

 

 

646

 

 

2,520

 

 

2,027

 

Gas (MMcf)

2,010

 

 

1,248

 

 

5,031

 

 

3,318

 

NGL (MBbls)

386

 

 

267

 

 

870

 

 

705

 

Total (MBoe)(4)

1,560

 

 

1,121

 

 

4,229

 

 

3,285

 

Average Daily Production (Boepd)

16,959

 

 

12,181

 

 

15,433

 

 

12,033

 

Average Prices:

 

 

 

 

 

 

 

Oil ($/Bbl)

39.50

 

 

54.89

 

 

36.92

 

 

55.08

 

Gas ($/Mcf)

1.31

 

 

0.72

 

 

0.96

 

 

0.64

 

NGL ($/Bbl)

13.60

 

 

10.71

 

 

11.46

 

 

15.17

 

Total ($/Boe)

26.31

 

 

34.98

 

 

25.50

 

 

37.89

 

Adj. for Realized Derivatives Settlements:

 

 

 

 

 

 

 

Oil ($/Bbl)(5)

49.34

 

 

59.43

 

 

55.14

 

 

60.42

 

Gas ($/Mcf)(5)

1.45

 

 

1.34

 

 

1.31

 

 

1.49

 

NGL ($/Bbl)

13.60

 

 

10.71

 

 

11.46

 

 

15.17

 

Total ($/Boe)(5)

31.78

 

 

38.29

 

 

36.77

 

 

42.05

 

Operating Margin per Boe

 

 

 

 

 

 

 

Average realized price(5)

$

26.31

 

 

$

34.98

 

 

$

25.50

 

 

$

37.89

 

Lease operating expense

4.51

 

 

5.73

 

 

5.20

 

 

6.24

 

Production and ad valorem taxes

1.73

 

 

2.41

 

 

1.70

 

 

2.44

 

Operating margin per Boe(2)

20.07

 

 

26.84

 

 

18.60

 

 

29.21

 

Realized hedge settlements

5.47

 

 

3.31

 

 

11.27

 

 

4.16

 

Operating margin per Boe (including realized hedge settlements)(2)

$

25.54

 

 

$

30.15

 

 

$

29.87

 

 

$

33.37

 

(1)

Net (loss) income per common share attributable to Earthstone Energy, Inc.

(2)

See “Non-GAAP Financial Measures” section below.

(3)

Represents reported sales volumes.

(4)

Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equals one barrel of oil equivalent (Boe).

(5)

Includes $5.7 million and $2.1 million of cash proceeds related to hedges unwound during the second quarter of 2020 and first quarter of 2019, respectively.

Liquidity Update

As of September 30, 2020, we had $5.3 million in cash and $130.0 million of long-term debt outstanding under our senior secured revolving credit facility (our “Credit Facility”) with a borrowing base of $240 million. With the $110.0 million of undrawn borrowing base capacity and $5.3 million in cash, we had total liquidity of approximately $115.3 million. Through September 30, 2020, we had incurred $46.4 million of our updated estimated $65 - $70 million in capital expenditures for 2020. We expect to fund our remaining 2020 capital expenditures through internally generated funds.

As of September 30, 2020, we had outstanding borrowings under our Credit Facility of $130 million, which represents a reduction of 24% compared to the $170 million in outstanding borrowings as of December 31, 2019. In addition to this $40 million of debt reduction, we have reduced our Adjusted Working Capital Deficit(1) by $23.4 million since December 31, 2019. We remain in compliance with all covenants under our Credit Facility.

(1)

See "Non-GAAP Financial Measures" section below.

 

Subsequent to September 30, 2020 and through October 31, 2020, we have paid down an additional $8 million in outstanding borrowings under our Credit Facility. This debt reduction is in line with our 2020 expectations to generate adequate cash flows to further reduce our outstanding borrowings absent any extraordinary events. However, it should be noted that we may borrow temporarily as the timing of our cash flows may fluctuate between reporting periods.

Commodity Hedging

The following table sets forth our outstanding derivative contracts as of September 30, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed.

As of September 30, 2020:

 

 

Price Swaps

Period

 

Commodity

 

Volume

(Bbls / MMBtu)

 

Weighted Average Price

($/Bbl / $/MMBtu)

Q4 2020

 

Crude Oil

 

552,000

 

 

$

60.65

 

Q1 - Q4 2021

 

Crude Oil

 

1,460,000

 

 

$

55.16

 

Q4 2020

 

Crude Oil Basis Swap (1)

 

598,000

 

 

$

(1.50

)

Q4 2020

 

Crude Oil Basis Swap (2)

 

92,000

 

 

$

2.55

 

Q4 2020

 

Crude Oil Roll Swap (3)

 

552,000

 

 

$

(1.79

)

Q1 - Q4 2021

 

Crude Oil Basis Swap (1)

 

1,825,000

 

 

$

1.05

 

Q4 2020

 

Natural Gas

 

644,000

 

 

$

2.85

 

Q1 - Q4 2021

 

Natural Gas

 

4,380,000

 

 

$

2.76

 

Q4 2020

 

Natural Gas Basis Swap (4)

 

644,000

 

 

$

(1.07

)

Q1 - Q4 2021

 

Natural Gas Basis Swap (4)

 

4,380,000

 

 

$

(0.45

)

(1)

The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX.

(2)

The basis differential price is between WTI Houston and the WTI NYMEX.

(3)

The swap is between WTI Roll and the WTI NYMEX.

(4)

The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.

 

Conference Call Details

Earthstone is hosting a conference call on Thursday, November 5, 2020 at 12:30 p.m. Eastern (11:30 a.m. Central) to discuss the Company’s financial results for the third quarter of 2020 and its outlook for the remainder of 2020. Prepared remarks by Robert J. Anderson, President and Chief Executive Officer, and Mark Lumpkin, Jr., Executive Vice President and Chief Financial Officer, will be followed by a question and answer session.

Investors and analysts are invited to participate in the call by dialing 877-407-6184 for domestic calls or 201-389-0877 for international calls, in both cases asking for the Earthstone conference call. A webcast will also be available through the Company website (www.earthstoneenergy.com). Please select “Events & Presentations” under the “Investors” section of the Company’s website and log on at least 10 minutes in advance to register.

A replay of the call and webcast will be available on the Company’s website and by telephone until 12:30 p.m. Eastern (11:30 a.m. Central), Thursday, November 19, 2020. The number for the replay is 877-660-6853 for domestic calls or 201-612-7415 for international calls, using Replay ID: 13712498.

About Earthstone Energy, Inc.

Earthstone Energy, Inc. is a growth-oriented, independent energy company engaged in development and operation of oil and natural gas properties. The Company’s primary assets are in the Midland Basin of west Texas and the Eagle Ford Trend of south Texas. Earthstone is traded on NYSE under the symbol “ESTE.” For more information, visit the Company’s website at www.earthstoneenergy.com.

Forward-Looking Statements

This release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not strictly historical statements constitute forward-looking statements and may often, but not always, be identified by the use of such words such as “expects,” “believes,” “intends,” “anticipates,” “plans,” “estimates,” “forecast,” “guidance,” “target,” “potential,” “possible,” or “probable” or statements that certain actions, events or results “may,” “will,” “should,” or “could” be taken, occur or be achieved. Forward-looking statements are based on current expectations and assumptions and analyses made by Earthstone and its management in light of experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances that involve various risks and uncertainties that could cause actual results to differ materially from those reflected in the statements. These risks include, but are not limited to, those set forth in Earthstone’s annual report on Form 10-K for the year ended December 31, 2019, quarterly reports on Form 10-Q, recent current reports on Form 8-K, and other Securities and Exchange Commission (“SEC”) filings. Earthstone undertakes no obligation to revise or update publicly any forward-looking statements except as required by law.

 

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except share and per share amounts)

 

 

 

September 30,

 

December 31,

ASSETS

 

2020

 

2019

Current assets:

 

 

 

 

Cash

 

$

5,311

 

 

$

13,822

 

Accounts receivable:

 

 

 

 

Oil, natural gas, and natural gas liquids revenues

 

12,097

 

 

29,047

 

Joint interest billings and other, net of allowance of $80 and $83 at

September 30, 2020 and December 31, 2019, respectively

 

11,548

 

 

6,672

 

Derivative asset

 

25,097

 

 

8,860

 

Prepaid expenses and other current assets

 

1,560

 

 

1,867

 

Total current assets

 

55,613

 

 

60,268

 

 

 

 

 

 

Oil and gas properties, successful efforts method:

 

 

 

 

Proved properties

 

995,666

 

 

970,808

 

Unproved properties

 

236,482

 

 

260,271

 

Land

 

5,382

 

 

5,382

 

Total oil and gas properties

 

1,237,530

 

 

1,236,461

 

 

 

 

 

 

Accumulated depreciation, depletion and amortization

 

(271,012

)

 

(195,567

)

Net oil and gas properties

 

966,518

 

 

1,040,894

 

 

 

 

 

 

Other noncurrent assets:

 

 

 

 

Goodwill

 

 

 

17,620

 

Office and other equipment, net of accumulated depreciation and amortization of

$3,558 and $3,180 at September 30, 2020 and December 31, 2019, respectively

 

1,044

 

 

1,311

 

Derivative asset

 

4,727

 

 

770

 

Operating lease right-of-use assets

 

2,769

 

 

3,108

 

Other noncurrent assets

 

1,331

 

 

1,572

 

TOTAL ASSETS

 

$

1,032,002

 

 

$

1,125,543

 

LIABILITIES AND EQUITY

 

 

 

 

Current liabilities:

 

 

 

 

Accounts payable

 

$

6,910

 

 

$

25,284

 

Revenues and royalties payable

 

28,047

 

 

35,815

 

Accrued expenses

 

12,844

 

 

19,538

 

Asset retirement obligation

 

308

 

 

308

 

Derivative liability

 

1,040

 

 

6,889

 

Advances

 

93

 

 

11,505

 

Operating lease liabilities

 

768

 

 

570

 

Finance lease liabilities

 

96

 

 

206

 

Other current liabilities

 

11

 

 

43

 

Total current liabilities

 

50,117

 

 

100,158

 

 

 

 

 

 

Noncurrent liabilities:

 

 

 

 

Long-term debt

 

130,000

 

 

170,000

 

Deferred tax liability

 

15,294

 

 

15,154

 

Asset retirement obligation

 

2,027

 

 

1,856

 

Derivative liability

 

577

 

 

 

Operating lease liabilities

 

2,001

 

 

2,539

 

Finance lease liabilities

 

15

 

 

85

 

Other noncurrent liabilities

 

138

 

 

 

Total noncurrent liabilities

 

150,052

 

 

189,634

 

 

 

 

 

 

Equity:

 

 

 

 

Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding

 

 

 

 

Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 30,210,749

and 29,421,131 issued and outstanding at September 30, 2020 and

December 31, 2019, respectively

 

30

 

 

29

 

Class B Common Stock, $0.001 par value, 50,000,000 shares authorized; 35,009,371 and

35,260,680 issued and outstanding at September 30, 2020 and

December 31, 2019, respectively

 

35

 

 

35

 

Additional paid-in capital

 

537,990

 

 

527,246

 

Accumulated deficit

 

(186,787

)

 

(181,711

)

Total Earthstone Energy, Inc. equity

 

351,268

 

 

345,599

 

Noncontrolling interest

 

480,565

 

 

490,152

 

Total equity

 

831,833

 

 

835,751

 

 

 

 

 

 

TOTAL LIABILITIES AND EQUITY

 

$

1,032,002

 

 

$

1,125,543

 

 

 

 

 

 

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except share and per share amounts)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

 

 

2020

 

2019

 

2020

 

2019

REVENUES

 

 

 

 

Oil

 

$

33,158

 

 

$

35,443

 

 

$

93,017

 

 

$

111,657

 

Natural gas

 

2,642

 

 

903

 

 

4,855

 

 

2,126

 

Natural gas liquids

 

5,247

 

 

2,858

 

 

9,976

 

 

10,691

 

Total revenues

 

41,047

 

 

39,204

 

 

107,848

 

 

124,474

 

 

 

 

 

 

 

 

 

 

OPERATING COSTS AND EXPENSES

 

 

 

 

 

 

 

 

Lease operating expense

 

7,044

 

 

6,419

 

 

21,971

 

 

20,485

 

Production and ad valorem taxes

 

2,696

 

 

2,698

 

 

7,198

 

 

8,001

 

Rig termination expense

 

 

 

 

 

426

 

 

 

Depreciation, depletion and amortization

 

28,538

 

 

14,079

 

 

76,096

 

 

42,281

 

Impairment expense

 

2,115

 

 

 

 

62,548

 

 

 

General and administrative expense

 

5,796

 

 

6,057

 

 

19,615

 

 

19,948

 

Transaction costs

 

(705

)

 

215

 

 

(324

)

 

797

 

Accretion of asset retirement obligation

 

47

 

 

52

 

 

137

 

 

160

 

Exploration expense

 

 

 

 

 

298

 

 

 

Total operating costs and expenses

 

45,531

 

 

29,520

 

 

187,965

 

 

91,672

 

 

 

 

 

 

 

 

 

 

(Loss) gain on sale of oil and gas properties

 

 

 

(120

)

 

198

 

 

(446

)

 

 

 

 

 

 

 

 

 

(Loss) income from operations

 

(4,484

)

 

9,564

 

 

(79,919

)

 

32,356

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

Interest expense, net

 

(1,186

)

 

(1,609

)

 

(4,207

)

 

(4,735

)

(Loss) gain on derivative contracts, net

 

(6,040

)

 

18,726

 

 

73,065

 

 

(19,672

)

Other income (expense), net

 

(18

)

 

21

 

 

120

 

 

(1

)

Total other income (expense)

 

(7,244

)

 

17,138

 

 

68,978

 

 

(24,408

)

 

 

 

 

 

 

 

 

 

(Loss) income before income taxes

 

(11,728

)

 

26,702

 

 

(10,941

)

 

7,948

 

Income tax expense

 

(130

)

 

(575

)

 

(112

)

 

(728

)

Net (loss) income

 

(11,858

)

 

26,127

 

 

(11,053

)

 

7,220

 

 

 

 

 

 

 

 

 

 

Less: Net (loss) income attributable to noncontrolling interest

 

(6,413

)

 

14,357

 

 

(5,977

)

 

3,877

 

 

 

 

 

 

 

 

 

 

Net (loss) income attributable to Earthstone Energy, Inc.

 

$

(5,445

)

 

$

11,770

 

 

$

(5,076

)

 

$

3,343

 

 

 

 

 

 

 

 

 

 

Net (loss) income per common share attributable to Earthstone Energy, Inc.:

 

 

 

 

 

 

 

 

Basic

 

$

(0.18

)

 

$

0.41

 

 

$

(0.17

)

 

$

0.12

 

Diluted

 

$

(0.18

)

 

$

0.41

 

 

$

(0.17

)

 

$

0.12

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

Basic

 

30,073,635

 

 

29,032,842

 

 

29,810,705

 

 

28,883,907

 

Diluted

 

30,073,635

 

 

29,032,842

 

 

29,810,705

 

 

28,883,907

 

 

 

 

 

 

 

 

 

 

EARTHSTONE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

 

 

 

For the Nine Months Ended
September 30,

 

 

2020

 

2019

Cash flows from operating activities:

 

 

Net (loss) income

 

$

(11,053

)

 

$

7,220

 

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

 

 

 

 

Depreciation, depletion and amortization

 

76,096

 

 

42,281

 

Impairment of proved and unproved oil and gas properties

 

44,928

 

 

 

Impairment of goodwill

 

17,620

 

 

 

Accretion of asset retirement obligations

 

137

 

 

160

 

Settlement of asset retirement obligations

 

 

 

(179

)

(Gain) loss on sale of oil and gas properties

 

(198

)

 

446

 

Total (gain) loss on derivative contracts, net

 

(73,065

)

 

19,672

 

Operating portion of net cash received in settlement of derivative contracts

 

47,599

 

 

13,660

 

Stock-based compensation

 

7,665

 

 

6,680

 

Deferred income taxes

 

112

 

 

728

 

Amortization of deferred financing costs

 

241

 

 

336

 

Changes in assets and liabilities:

 

 

 

 

(Increase) decrease in accounts receivable

 

12,102

 

 

(5,585

)

(Increase) decrease in prepaid expenses and other current assets

 

(264

)

 

(28

)

Increase (decrease) in accounts payable and accrued expenses

 

1,976

 

 

(8,330

)

Increase (decrease) in revenues and royalties payable

 

(7,768

)

 

(9,042

)

Increase (decrease) in advances

 

(11,412

)

 

17,720

 

Net cash provided by operating activities

 

104,716

 

 

85,739

 

Cash flows from investing activities:

 

 

 

 

Additions to oil and gas properties

 

(72,869

)

 

(120,685

)

Additions to office and other equipment

 

(111

)

 

(379

)

Proceeds from sales of oil and gas properties

 

409

 

 

2

 

Net cash used in investing activities

 

(72,571

)

 

(121,062

)

Cash flows from financing activities:

 

 

 

 

Proceeds from borrowings

 

93,923

 

 

165,272

 

Repayments of borrowings

 

(133,923

)

 

(119,099

)

Cash paid related to the exchange and cancellation of Class A Common Stock

 

(531

)

 

(827

)

Cash paid for finance leases

 

(125

)

 

(355

)

Deferred financing costs

 

 

 

(228

)

Net cash (used in) provided by financing activities

 

(40,656

)

 

44,763

 

Net (decrease) increase in cash

 

(8,511

)

 

9,440

 

Cash at beginning of period

 

13,822

 

 

376

 

Cash at end of period

 

$

5,311

 

 

$

9,816

 

Supplemental disclosure of cash flow information

 

 

 

 

Cash paid for:

 

 

 

 

Interest

 

$

3,613

 

 

$

4,235

 

Non-cash investing and financing activities:

 

 

 

 

Accrued capital expenditures

 

$

2,213

 

 

$

50,615

 

Lease asset additions - ASC 842

 

$

 

 

$

4,710

 

Asset retirement obligations

 

$

44

 

 

$

43

 

 

Earthstone Energy, Inc.
Non-GAAP Financial Measures
Unaudited

The non-GAAP financial measures of Adjusted Diluted Shares, Adjusted EBITDAX, Adjusted Net Income, All-In Cash Costs, Free Cash Flow, Adjusted Working Capital Deficit and Operating Margin per Boe, as defined and presented below, are intended to provide readers with meaningful information that supplements our financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). Further, these non-GAAP measures should only be considered in conjunction with financial statements and disclosures prepared in accordance with GAAP and should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of financial position or results of operations. Adjusted EBITDAX and Adjusted Net Income are presented herein and reconciled from the GAAP measure of net (loss) income because of their wide acceptance by the investment community as a financial indicator.

I. Adjusted Diluted Shares

We define “Adjusted Diluted Shares” as the weighted average shares of Class A Common Stock - Diluted outstanding plus the weighted average shares of Class B Common Stock outstanding.

Our Adjusted Diluted Shares measure provides a comparable per share measurement when presenting results such as Adjusted EBITDAX and Adjusted Net Income that include the interests of both Earthstone and the noncontrolling interest. Adjusted Diluted Shares is used in calculating several metrics that we use as supplemental financial measurements in the evaluation of our business, none of which should be considered as an alternative to, or more meaningful than, net income as an indicator of operating performance.


Contacts

Mark Lumpkin, Jr.
Executive Vice President – Chief Financial Officer
Earthstone Energy, Inc.
1400 Woodloch Forest Drive, Suite 300
The Woodlands, TX 77380
281-298-4246
This email address is being protected from spambots. You need JavaScript enabled to view it.

Scott Thelander
Vice President of Finance
Earthstone Energy, Inc.
1400 Woodloch Forest Drive, Suite 300
The Woodlands, TX 77380
281-298-4246
This email address is being protected from spambots. You need JavaScript enabled to view it.


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Table of Contents:

Executive Summary

Market Landscape

  • Market ecosystem
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Market Sizing

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  • Market outlook: Forecast for 2019 - 2024

Five Forces Analysis

  • Five forces analysis
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  • Threat of rivalry
  • Market condition

Market Segmentation by Application

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  • Commercial - Market size and forecast 2019-2024
  • Residential - Market size and forecast 2019-2024
  • Market opportunity by Application

Customer landscape

  • Overview

Geographic Landscape

  • Geographic segmentation
  • Geographic comparison
  • APAC - Market size and forecast 2019-2024
  • North America - Market size and forecast 2019-2024
  • MEA - Market size and forecast 2019-2024
  • Europe - Market size and forecast 2019-2024
  • South America - Market size and forecast 2019-2024
  • Key leading countries
  • Market opportunity by geography
  • Market drivers
  • Market challenges
  • Market trends

Vendor Landscape

  • Overview
  • Landscape disruption
  • Competitive scenario

Vendor Analysis

  • Vendors covered
  • Market positioning of vendors
  • AGC Inc.
  • Borosil Glass Works Ltd.
  • Euro Multivision Ltd.
  • Interfloat Corp.
  • Nippon Sheet Glass Co. Ltd.
  • ONYX SOLAR ENERGY SL
  • Sisecam Group
  • Taiwan Glass Ind. Corp.
  • Targray Technology International Inc.
  • Xinyi Solar Holdings Ltd.

Appendix

  • Scope of the report
  • Currency conversion rates for US$
  • Research methodology
  • List of abbreviations

     

About Us

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MINNEAPOLIS--(BUSINESS WIRE)--Northern Oil and Gas, Inc. (NYSE American: NOG) (the “Company” or “Northern”) today announced that the borrowing base under its reserves-based revolving credit facility has been reaffirmed at $660.0 million. The 14 lender syndicate unanimously reaffirmed this amount, effective as of November 2, 2020. No changes were made to the terms of the credit facility, and Northern is in full compliance with all covenants. Northern anticipates ample cash on hand and liquidity to satisfy its sole short-term amortization payment in January 2021.


HEDGING UPDATE

Northern remains majority hedged on its projected oil production at above-market prices through 2021. Additionally, Northern has 5,000 barrels/day hedged at $51.77/barrel for the first quarter of 2022 and 1,000 barrels/day hedged at $50.05/bbl for the remaining three quarters of 2022. The following table summarizes Northern’s crude oil swap contracts.

Period

Production

NYMEX WTI Price

Q4:20

~25.8 Mbo/d

~$58.03

2021

~19.4 Mbo/d

~$55.68

Q1:22

~5.0 Mbo/d

~$51.77

Q2-Q4:22

~1.0 Mbo/d

~$50.05

MANAGEMENT COMMENT

“We are pleased that our strong reserves base and excellent hedge profile continue to support a reaffirmation of our borrowing base,” commented Chad Allen, Northern’s Chief Financial Officer, “Due to Northern’s free cash flow profile, Northern anticipates substantial reductions in facility borrowings by year end 2021. While we don’t require significant liquidity to operate, our business plan should deliver a strong liquidity base for potential acquisitions and debt reduction over time.”

ABOUT NORTHERN OIL AND GAS

Northern Oil and Gas, Inc. is a company with a primary strategy of investing in non-operated minority working and mineral interests in oil & gas properties, with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana. More information about Northern Oil and Gas, Inc. can be found at www.northernoil.com.

SAFE HARBOR

This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, operating and financial performance, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: the effects of the COVID-19 pandemic and related economic slowdown, changes in crude oil and natural gas prices, the pace of drilling and completions activity on Northern’s current properties, infrastructure constraints and related factors affecting Northern’s properties, ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline, Northern’s ability to acquire additional development opportunities, Northern’s ability to consummate any pending acquisition transactions, other risks and uncertainties related to the closing of pending acquisition transactions, changes in Northern’s reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which Northern conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern’s ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, health-related epidemics, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern’s operations, products and prices.

Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control. Northern does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws.


Contacts

Mike Kelly, CFA
EVP Finance
952-476-9800
This email address is being protected from spambots. You need JavaScript enabled to view it.

  • Company sets 2021 guidance of $2.15-$2.35 EPS and adjusted EPS
  • Sustainable business model drives growth through ESG+F framework
  • Financial outlook of 6-8% EPS and adjusted EPS compound annual growth rate (CAGR) for 2020-2025 including PNM Resources; merger expected to close in the fourth quarter of 2021
  • Over $20B capital spending through 2025 in regulated and contracted businesses

ORANGE, Conn.--(BUSINESS WIRE)--$AGR--AVANGRID, Inc. (NYSE: AGR), a leading sustainable energy company, will hold its first virtual investor day from its Corporate Headquarters in Orange, Connecticut on November 5, 2020 at 1:00 p.m. Eastern Time. The executive team will provide the investment community with its 2021 earnings guidance as well as details on the Company’s long-term strategic platform and financial outlook through 2025, including the previously announced merger with PNM Resources. The company will outline its sustainable business model for building a leading clean energy company based on an ESG+F (Environment, Social, Governance and Financial performance) framework that will drive growth and enable strategic investments and innovation.


“AVANGRID is leading the transition to a prosperous clean energy future. We are focused on developing energy solutions to transform and enhance the economic, social and environmental value we deliver to our customers, employees, partners and shareholders,” said AVANGRID CEO Dennis V. Arriola.

Arriola continued, “Enabled by our strong financial position, we will expand both our Networks and Renewables businesses by investing in new, cleaner energy technologies, pioneering the offshore wind industry in the US, and growing our footprint through our recently announced agreement to merge with PNM Resources.”

The company will provide details at its Investor Day on its 2021 earnings guidance of $2.15-$2.35 per share and a long-term outlook to deliver 6-8% annual EPS and adjusted EPS growth between 2020 and 2025. In addition, the company plans to invest over $20 billion in regulated and contracted investments, including $4.3 billion associated with the merger of PNM Resources. The company’s 2021 guidance excludes PNM Resources and the impacts of the pending merger and related transaction costs.

Full access to the AVANGRID Investor Day presentations and broadcast will be available in the Investors’ section on the company’s website at avangrid.com.

About AVANGRID: AVANGRID, Inc. (NYSE: AGR) is a leading, sustainable energy company with approximately $36 billion in assets and operations in 24 U.S. states. With headquarters in Orange, Connecticut, AVANGRID has two primary lines of business: Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving more than 3.3 million customers in New York and New England. Avangrid Renewables owns and operates a portfolio of renewable energy generation facilities across the United States. AVANGRID employs approximately 6,600 people. AVANGRID supports the U.N.’s Sustainable Development Goals and was named among the World’s Most Ethical Companies in 2019 and 2020 by the Ethisphere Institute. For more information, visit www.avangrid.com.

About PNM Resources: PNM Resources (NYSE: PNM) is an energy holding company based in Albuquerque, NM, with 2019 consolidated operating revenues of $1.5 billion. Through its regulated utilities, PNM and TNMP, PNM Resources has approximately 2,811 megawatts of generation capacity and provides electricity to approximately 790,000 homes and businesses in New Mexico and Texas. For more information, visit the company's website at www.PNMResources.com.

FORWARD LOOKING STATEMENTS

Certain statements in this presentation may relate to our future business and financial performance and future events or developments involving us and our subsidiaries that are not purely historical and may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements may be identified by the use of forward-looking terms such as “may,” “will,” “should,” “would,” “could,” “can,” “expect(s),” “believe(s),” “anticipate(s),” “intend(s),” “plan(s),” “estimate(s),” “project(s),” “assume(s),” “guide(s),” “target(s),” “forecast(s),” “outlook(s)”, “predicts”, “are (is) confident that” and “seek(s)” or the negative of such terms or other variations on such terms or comparable terminology. Such forward-looking statements include, but are not limited to, statements about our plans, objectives and intentions, outlooks or expectations for earnings, revenues, expenses or other future financial or business performance, strategies or expectations, or the impact of legal or regulatory matters on business, results of operations or financial condition of the business and other statements that are not historical facts. Such statements are based upon the current reasonable beliefs, expectations, and assumptions of our management and are subject to significant risks and uncertainties that could cause actual outcomes and results to differ materially. Important factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC. Specifically, forward-looking statements include, without limitation: the future financial performance, anticipated liquidity and capital expenditures, actions or inactions of local, state or federal regulatory agencies, success in retaining or recruiting our officers, key employees or directors, changes in levels or timing of capital expenditures, adverse developments in general market, business, economic, labor, regulatory and political conditions, fluctuations in weather patterns, technological developments, the impact of any cyber breaches or other incidents, grid disturbances, acts of war or terrorism, civil or social unrest, natural disasters, pandemic health events or other similar occurrences, the impact of any change to applicable laws and regulations affecting operations, including those relating to the environment and climate change, taxes, price controls, regulatory approval and permitting, the implementation of changes in accounting standards; and other presently unknown unforeseen factors.

Should one or more of these risks or uncertainties materialize, or should any of the underlying assumptions prove incorrect, actual results may vary in material respects from those expressed or implied by these forward-looking statements. The information in this presentation was prepared as of November 5, 2020. You should not place undue reliance on these forward-looking statements. We do not undertake any obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this report, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. Other risk factors are detailed from time to time in our reports filed with the SEC, and we encourage you to consult such disclosures.

This presentation shall not constitute an offer to sell or the solicitation of an offer to buy securities. Any offers, solicitations or offers to buy, or any sales of securities will be made in accordance with the requirements of the Securities Act of 1933, as amended. This document is not intended for use in connection with any sale, offer to sell, or solicitation of any offer to buy securities.

USE OF NON-U.S. GAAP FINANCIAL MEASURES

To supplement our consolidated financial statements presented in accordance with GAAP, we consider cash from operations pre-working capital, total debt, adjusted net income and adjusted earnings per share, or adjusted EPS, as non-GAAP financial measures that are not prepared in accordance with GAAP. The non-GAAP financial measures we use are specific to AVANGRID and the non-GAAP financial measures of other companies may not be calculated in the same manner. We use these non-GAAP financial measures, in addition to GAAP measures, to establish operating budgets and operational goals to manage and monitor our business, evaluate our operating and financial performance and to compare such performance to prior periods and to the performance of our competitors. We believe that presenting such non-GAAP financial measures is useful because such measures can be used to analyze and compare profitability between companies and industries by eliminating the impact of certain non-cash charges. In addition, we present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance.

We define adjusted net income as net income adjusted to exclude restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity, accelerated depreciation derived from repowering of wind farms, and the impact of the global coronavirus (COVID-19) pandemic. We believe adjusted net income is more useful in understanding and evaluating actual and projected financial performance and contribution of AVANGRID core lines of business and to more fully compare and explain our results. The most directly comparable GAAP measure to adjusted net income is net income. We also define adjusted earnings per share, or adjusted EPS, as adjusted net income converted to an earnings per share amount. Cash from operations pre-working capital is defined as cash flow from operations plus changes in working capital and changes in other current assets and liabilities, plus employer pension costs, net of service costs and depreciation on operating leases, less capitalized interest. The most directly comparable GAAP measure to cash from operations pre- working capital is cash from operations. Total debt is defined as short-term debt plus long term debt adjusted to add pension liabilities, operating leases and unamortized debt. The most directly comparable GAAP measure to total debt is long-term debt.

In addition, we have presented certain financial information that reflects the consummation of the pending merger of AVANGRID with PNM Resources to supplement evaluation of AVANGRID and its ongoing operations. Combined information combines the results of PNM Resources with AVANGRID as if the merger had occurred on the last day of 2021. All combined information included in this presentation is unaudited and not prepared in accordance with GAAP or Article 11 of Regulation S-X.

The use of non-GAAP financial measures is not intended to be considered in isolation or as a substitute for, or superior to, AVANGRID’s GAAP financial information, and investors are cautioned that the non-GAAP financial measures are limited in their usefulness, may be unique to AVANGRID, and should be considered only as a supplement to AVANGRID’s GAAP financial measures. The non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools.

Non-GAAP financial measures are not primary measurements of our performance under GAAP and should not be considered as alternatives to operating income, net income or any other performance measures determined in accordance with GAAP.

We use the following non-GAAP metrics for completed periods in our presentation, which are reconciled to their closest GAAP financial measure in the Appendix: cash from operations pre-working capital, total debt, adjusted net income and adjusted EPS. For projection purposes, there is no difference between net income and adjusted net income and EPS and adjusted EPS.

Investors and others should note that AVANGRID routinely posts important information on its website and considers the Investor Relations section, www.avangrid.com/wps/portal/avangrid/Investors, a channel of distribution.

GUIDANCE AND FINANCIAL OUTLOOK

The guidance and financial outlook information included in this presentation includes forward-looking non-GAAP financial measures, which management uses in measuring performance. However, we are not able to reconcile non-GAAP information for incomplete or future periods to the corresponding GAAP measure without unreasonable efforts, due to the unavailability of, and our inability to reliably forecast, certain of the underlying amounts and because it is not possible to predict with a reasonable degree of certainty the actual impact of various items through those periods, including: the exact timing and amount of acquisitions, divestitures, capital expenditures and/or structural changes; and the exact timing and amount of comparability items throughout 2020 or future periods. The unavailable information and variability of any underlying items could have a significant impact on GAAP financial results for 2020 and future periods.

PNM RESOURCES

This presentation includes certain information relating to our pending merger with PNM Resources, including forward-looking information. In addition, certain of the guidance and other projections included herein include, among other matters, projected results for Avangrid after giving effect to its merger with PMN Resources, anticipated investments and capital expenditures, as well as other potential unidentified acquisitions and transactions. The merger with PNM Resources is subject to PNM Resources shareholder approval, regulatory approvals from the New Mexico Public Regulation Commission, Public Utility Commission of Texas, Federal Energy Regulatory Commission, Department of Justice (Hart Scott-Rodino Clearance), Nuclear Regulatory Commission, Federal Communications Commission and Committee on Foreign Investment in the United States, and other customary closing conditions. The transaction is expected to close between October and December 2021. As noted herein, we have included herein certain guidance and other projections for PNM Resources based on their prior presentations and their inclusion herein does not constitute the reaffirmation of such guidance and other projections as of the date of this presentation. In addition, as noted herein we have created and included herein certain guidance and other projections for PNM Resources for certain future periods, and for Avangrid after giving effect to the merger with PNM Resources, that have not been created or confirmed by PNM Resources or its representatives.

Additional Information

The proposed business combination transaction between PNMR and Avangrid will be submitted to the shareholders of PNMR for their consideration. PNMR will file a proxy statement and other documents with the SEC regarding the proposed business combination transaction. INVESTORS AND SECURITY HOLDERS ARE URGED TO READ THE PROXY STATEMENT AND ANY OTHER RELEVANT DOCUMENTS THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. You may obtain copies of all documents filed with the SEC regarding this transaction, free of charge, at the SEC’s website (www.sec.gov).

Avangrid, Inc., PNM and certain of their respective directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies from PNM’s shareholders in connection with the transactions presented in this presentation. Information regarding the persons who may, under the rules of the SEC, be deemed participants in the solicitation of PNM’s shareholders in connection with the transactions presented in this presentation will be set forth in the Proxy Statement when it is filed with the SEC. Additional information about Avangrid Inc.’s executive officers and directors and PNM’s executive officers and directors can be found in the Proxy Statement when it becomes available.

This press release is not, and shall not be deemed to be, an offer to sell or a solicitation of an offer to buy any interest or securities of any person, or an offer to enter into any transaction. Accordingly, neither Avangrid nor any other member of the Avangrid group will be under any legal or other obligation of any kind whatsoever to negotiate or consummate any transaction, and neither the recipient hereof nor any of its affiliates or other persons shall have any claim whatsoever against the Avangrid group (or any of its directors, officers, owners or affiliates) arising out of or relating to the information contained herein.


Contacts

Media:
Zsoka McDonald, 203-997-6892 or This email address is being protected from spambots. You need JavaScript enabled to view it.

Investors:
Patricia Cosgel, 203-499-2624 or This email address is being protected from spambots. You need JavaScript enabled to view it.

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.


Contacts

Investor relations
(587) 476-4743

Media relations
(587) 476-7010

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:

Key Indicators

3Q2020

2Q2020

3Q2019

9M2020

9M2019

Oil productiona (bopd)

32,875

32,504

33,693

35,404

34,102

Gas production (mcfpd)

35,814

26,448

35,555

30,509

32,148

Average net production (boepd)

38,845

36,912

39,619

40,490

39,460

Brent oil price ($ per bbl)

43.3

33.1

62.1

42.5

64.7

Combined realized price ($ per boe)

27.9

17.8

44.2

27.3

46.4

⁻ Oil ($ per bbl)

31.7

18.6

49.3

29.8

51.3

⁻ Gas ($ per mcf)

2.5

2.8

4.4

3.0

4.6

Sale of crude oil ($ million)

89.3

49.0

138.2

262.2

434.6

Sale of gas ($ million)

8.8

6.6

13.0

24.9

36.2

Revenue ($ million)

98.1

55.7

151.2

287.0

470.9

Commodity risk management contracts ($ million)

2.7

-9.1

4.4

25.6

-16.0

Production & operating costsb ($ million)

-28.4

-20.7

-41.7

-90.2

-126.7

G&G, G&AC and selling expenses ($ million)

-14.4

-15.9

-21.1

-49.4

-63.7

Adjusted EBITDA ($ million)

56.1

27.8

86.7

161.6

277.7

Adjusted EBITDA ($ per boe)

15.9

8.9

25.3

15.3

27.4

Operating Netback ($ per boe)

19.2

13.0

31.4

19.2

33.0

Net Profit (loss) ($ million)

-4.3

-19.9

6.8

-113.7

57.9

Capital expenditures ($ million)

9.8

5.8

22.1

49.3

88.2

Amerisur acquisitiond ($ million)

-

-

-

272.3

-

Cash and cash equivalents ($ million)

163.7

157.5

81.6

163.7

81.6

Short-term financial debt ($ million)

4.8

19.9

10.6

4.8

10.6

Long-term financial debt ($ million)

767.4

763.5

424.4

767.4

424.4

Net debt ($ million)

608.4

625.9

353.4

608.4

353.4

a) Includes royalties paid in kind in Colombia for approximately 1,284, 1,286 and 1,419 bopd in 3Q2020, 2Q2020 and 3Q2019 respectively. No royalties were paid in kind in Chile, Brazil or Argentina.

b) Production and operating costs include operating costs and royalties paid in cash.

c) G&A and G&G expenses include non-cash, share-based payments for $1.8 million, $2.0 million and $0.3 million in 3Q2020, 2Q2020 and 3Q2019, respectively. These expenses are excluded from the Adjusted EBITDA calculation.

d) Amerisur acquisition is shown net of cash acquired.

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:

3Q2020 - Realized Oil Prices

($ per bbl)

Colombia

Chile

Argentina

Brent oil price (*)

43.3

42.7

43.3

Local marker differential

(3.0)

-

-

Commercial and transportation discounts

(9.0)

(7.7)

-

Other

-

-

(2.8)

Realized oil price

31.3

35.0

40.5

Weight on oil sales mix

94%

1%

5%

3Q2019 - Realized Oil Prices

($ per bbl)

Colombia

Chile

Argentina

Brent oil price (*)

62.1

62.0

62.1

Local marker differential

(1.7)

-

-

Commercial and transportation discounts

(11.1)

(7.7)

-

Other

-

-

(13.2)

Realized oil price

49.3

54.3

48.9

Weight on oil sales mix

94%

1%

5%

(*) Specified Brent oil price differs in each country as sales in Colombia are priced with reference to ICE Brent whereas sales in Chile are priced with reference to Dated Brent. In Argentina, local prices are dissociated from international oil prices and differences between international benchmarks and realized prices are included in “Other”.

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:

(In millions of $)

3Q2020

3Q2019

Operating costs

19.9

26.6

Royalties

8.4

15.1

Share-based payments

0.1

-

Production and operating costs

28.4

41.7

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:

Adjusted EBITDA/boe

Colombia

Chile

Brazil

Argentina

Total

 

3Q20

3Q19

3Q20

3Q19

3Q20

3Q19

3Q20

3Q19

3Q20

3Q19

Production (boepd)

31,297

31,578

3,610

3,358

1,581

2,299

2,357

2,384

38,845

39,619

Inventories, RIKa & Other

(251)

(1,629)

(20)

(311)

(117)

(190)

(213)

(285)

(601)

(2,414)

Sales volume (boepd)

31,046

29,949

3,590

3,047

1,464

2,109

2,144

2,099

38,244

37,205

% Oil

96.5%

99.5%

10%

15%

1%

2%

66%

71%

83%

85%

($ per boe)

 

 

 

 

 

 

 

 

 

 

Realized oil price

31.3

49.3

35.0

54.3

40.6

69.2

40.5

48.9

31.7

49.3

Realized gas priceb

5.3

34.5

14.1

24.4

24.8

29.7

12.4

17.4

14.8

25.9

Earn-out

(1.2)

(2.2)

-

-

-

-

-

-

(1.0)

(1.7)

Combined Price

29.2

47.0

16.2

28.9

25.0

30.4

31.1

39.8

27.9

44.2

Realized commodity risk management contracts

0.5

0.5

-

 

-

 

-

 

0.4

0.4

Operating costs

(5.9)

(5.6)

(5.3)

(19.3)

(5.8)

(7.9)

(14.9)

(27.0)

(6.3)

(8.1)

Royalties in cash

(2.4)

(4.8)

(0.6)

(1.0)

(2.3)

(2.3)

(5.0)

(6.1)

(2.4)

(4.4)

Selling & other expenses

(0.3)

(0.7)

(0.2)

(0.3)

-

-

(2.2)

(1.3)

(0.4)

(0.7)

Operating Netback/boe

21.1

36.4

10.1

8.2

17.0

20.1

9.0

5.4

19.2

31.4

G&A, G&G & other

 

 

 

 

 

 

 

 

(3.3)

(6.1)

Adjusted EBITDA/boe

 

 

 

 

 

 

 

 

15.9

25.3

a) RIK (Royalties in kind). Includes royalties paid in kind in Colombia for approximately 1,284 and 1,419 bopd in 3Q2020 and 3Q2019 respectively. No royalties were paid in kind in Chile, Brazil or Argentina.

b) Conversion rate of $mcf/$boe=1/6.

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 RATIOSa

(In millions of $)

Period-end

 

Financial
Debt

 

Cash and Cash
Equivalents

 

Net Debt

 

Net Debt/LTM
Adj. EBITDA

 

LTM Interest
Coverage

 

 

 

 

 

3Q2019

 

435.0

 

81.6

 

353.4

 

1.0x

 

12.1x

4Q2019

 

437.4

 

111.2

 

326.2

 

0.9x

 

12.1x

1Q2020

 

775.3

 

165.5

 

609.9

 

1.7x

 

11.6x

2Q2020

 

783.4

 

157.5

 

625.9

 

2.3x

 

7.2x

3Q2020

 

772.2

 

163.7

 

608.4

 

2.5x

 

5.7x

a)

Based on trailing last twelve-month financial results (“LTM”).

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.


Contacts

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.

 

 
 
 
 

ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(unaudited)

 

 

September 30,

2020

 

December 31,

2019

ASSETS

 

 

 

Current assets (1)

$

6,150

 

 

$

7,464

 

 

 

 

 

Property, plant and equipment, net

75,128

 

 

74,193

 

 

 

 

 

Advances to and investments in unconsolidated affiliates

3,068

 

 

3,460

 

Lease right-of-use assets, net

934

 

 

964

 

Other non-current assets, net (1)

1,582

 

 

1,571

 

Intangible assets, net

5,915

 

 

6,154

 

Goodwill

2,418

 

 

5,167

 

Total assets

$

95,195

 

 

$

98,973

 

LIABILITIES AND EQUITY

 

 

 

Current liabilities

$

6,047

 

 

$

7,724

 

 

 

 

 

Long-term debt, less current maturities

51,424

 

 

51,028

 

Non-current derivative liabilities

275

 

 

273

 

Non-current operating lease liabilities

901

 

 

901

 

Deferred income taxes

3,349

 

 

3,208

 

Other non-current liabilities

1,152

 

 

1,162

 

 

 

 

 

Commitments and contingencies

 

 

 

Redeemable noncontrolling interests

756

 

 

739

 

 

 

 

 

Equity:

 

 

 

Total partners’ capital

18,284

 

 

21,920

 

Noncontrolling interests

13,007

 

 

12,018

 

Total equity

31,291

 

 

33,938

 

Total liabilities and equity

$

95,195

 

 

$

98,973

 

(1)

 

 

Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory.  Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non current assets. The balances as of December 31, 2019 have been adjusted to reflect this change in accounting policy.

 
 
 
 
 

ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)

(unaudited)

 

 

Three Months Ended

September 30,

 

Nine Months Ended

September 30,

 

2020

 

2019(1)

 

2020

 

2019(1)

REVENUES

$

9,955

 

 

$

13,495

 

 

$

28,920

 

 

$

40,493

 

COSTS AND EXPENSES:

 

 

 

 

 

 

 

Cost of products sold

6,376

 

 

9,864

 

 

18,784

 

 

29,642

 

Operating expenses

773

 

 

806

 

 

2,422

 

 

2,406

 

Depreciation, depletion and amortization

912

 

 

784

 

 

2,715

 

 

2,343

 

Selling, general and administrative

176

 

 

173

 

 

555

 

 

499

 

Impairment losses

1,474

 

 

12

 

 

2,803

 

 

62

 

Total costs and expenses

9,711

 

 

11,639

 

 

27,279

 

 

34,952

 

OPERATING INCOME

244

 

 

1,856

 

 

1,641

 

 

5,541

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

Interest expense, net of interest capitalized

(569

)

 

(579

)

 

(1,750

)

 

(1,747

)

Equity in earnings (losses) of unconsolidated affiliates

(32

)

 

82

 

 

46

 

 

224

 

Impairment of investment in an unconsolidated affiliate

(129

)

 

 

 

(129

)

 

 

Losses on extinguishments of debt

 

 

 

 

(62

)

 

(18

)

Gains (losses) on interest rate derivatives

55

 

 

(175

)

 

(277

)

 

(371

)

Other, net

71

 

 

57

 

 

6

 

 

99

 

INCOME (LOSS) BEFORE INCOME TAX EXPENSE

(360

)

 

1,241

 

 

(525

)

 

3,728

 

Income tax expense

41

 

 

54

 

 

168

 

 

214

 

NET INCOME (LOSS)

(401

)

 

1,187

 

 

(693

)

 

3,514

 

Less: Net income attributable to noncontrolling interests

369

 

 

317

 

 

554

 

 

931

 

Less: Net income attributable to redeemable noncontrolling interests

12

 

 

12

 

 

37

 

 

38

 

NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS

(782

)

 

858

 

 

(1,284

)

 

2,545

 

General Partner’s interest in net income (loss)

 

 

1

 

 

(1

)

 

3

 

Limited Partners’ interest in net income (loss)

$

(782

)

 

$

857

 

 

$

(1,283

)

 

$

2,542

 

NET INCOME (LOSS) PER LIMITED PARTNER UNIT:

 

 

 

 

 

 

 

Basic

$

(0.29

)

 

$

0.33

 

 

$

(0.48

)

 

$

0.97

 

Diluted

$

(0.29

)

 

$

0.33

 

 

$

(0.48

)

 

$

0.97

 

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING:

 

 

 

 

 

 

 

Basic

2,696.6

 

 

2,624.9

 

 

2,694.4

 

 

2,621.9

 

Diluted

2,696.6

 

 

2,635.5

 

 

2,694.4

 

 

2,632.9

 

(1)

 

 

Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non-current assets. The condensed consolidated statement of operations for the three and nine months ended September 30, 2019 has been adjusted to reflect this change in accounting policy.

 
 
 
 
 

ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
(Dollars and units in millions)

(unaudited)

 

 

Three Months Ended

September 30,

 

Nine Months Ended

September 30,

 

2020

 

2019(a)

 

2020

 

2019(a)

Reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow(b):

 

 

 

 

 

 

 

Net income (loss)

$

(401

)

 

$

1,187

 

 

$

(693

)

 

$

3,514

 

Interest expense, net of interest capitalized

569

 

 

579

 

 

1,750

 

 

1,747

 

Impairment losses

1,474

 

 

12

 

 

2,803

 

 

62

 

Income tax expense

41

 

 

54

 

 

168

 

 

214

 

Depreciation, depletion and amortization

912

 

 

784

 

 

2,715

 

 

2,343

 

Non-cash compensation expense

30

 

 

27

 

 

93

 

 

85

 

(Gains) losses on interest rate derivatives

(55

)

 

175

 

 

277

 

 

371

 

Unrealized (gains) losses on commodity risk management activities

30

 

 

(64

)

 

27

 

 

(90

)

Losses on extinguishments of debt

 

 

 

 

62

 

 

18

 

Impairment of investment in an unconsolidated affiliate

129

 

 

 

 

129

 

 

 

Inventory valuation adjustments (Sunoco LP)

(11

)

 

26

 

 

126

 

 

(71

)

Equity in (earnings) losses of unconsolidated affiliates

32

 

 

(82

)

 

(46

)

 

(224

)

Adjusted EBITDA related to unconsolidated affiliates

169

 

 

161

 

 

480

 

 

470

 

Other, net

(53

)

 

(47

)

 

48

 

 

(67

)

Adjusted EBITDA (consolidated)

2,866

 

 

2,812

 

 

7,939

 

 

8,372

 

Adjusted EBITDA related to unconsolidated affiliates

(169

)

 

(161

)

 

(480

)

 

(470

)

Distributable cash flow from unconsolidated affiliates

128

 

 

107

 

 

353

 

 

307

 

Interest expense, net of interest capitalized

(569

)

 

(579

)

 

(1,750

)

 

(1,747

)

Preferred unitholders’ distributions

(97

)

 

(68

)

 

(282

)

 

(185

)

Current income tax expense

(7

)

 

(2

)

 

(8

)

 

(23

)

Maintenance capital expenditures

(129

)

 

(178

)

 

(368

)

 

(440

)

Other, net

17

 

 

18

 

 

57

 

 

55

 

Distributable Cash Flow (consolidated)

2,040

 

 

1,949

 

 

5,461

 

 

5,869

 

Distributable Cash Flow attributable to Sunoco LP (100%)

(139

)

 

(133

)

 

(419

)

 

(331

)

Distributions from Sunoco LP

41

 

 

41

 

 

123

 

 

123

 

Distributable Cash Flow attributable to USAC (100%)

(57

)

 

(55

)

 

(170

)

 

(164

)

Distributions from USAC

24

 

 

24

 

 

72

 

 

66

 

Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owned consolidated subsidiaries

(234

)

 

(283

)

 

(733

)

 

(827

)

Distributable Cash Flow attributable to the partners of ET

1,675

 

 

1,543

 

 

4,334

 

 

4,736

 

Transaction-related adjustments

16

 

 

3

 

 

46

 

 

6

 

Distributable Cash Flow attributable to the partners of ET, as adjusted

$

1,691

 

 

$

1,546

 

 

$

4,380

 

 

$

4,742

 

Distributions to partners:

 

 

 

 

 

 

 

Limited Partners

$

411

 

 

$

808

 

 

2,055

 

 

2,407

 

General Partner

1

 

 

1

 

 

3

 

 

3

 

Total distributions to be paid to partners

$

412

 

 

$

809

 

 

$

2,058

 

 

$

2,410

 

Common Units outstanding – end of period

2,698.0

 

 

2,627.0

 

 

2,698.0

 

 

2,627.0

 

Distribution coverage ratio

4.10x

 

1.91x

 

2.13x

 

1.97x

(a)

 

Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non-current assets. The results for the three and nine months ended September 30, 2019 have been adjusted to reflect this change in accounting policy.

(b)

Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio are non-GAAP financial measures used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of ET’s fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities or other GAAP measures.

 
 

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.

 
 
 
 
 

ENERGY TRANSFER LP AND SUBSIDIARIES
SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)

(unaudited)

 

 

Three Months Ended

September 30,

 

2020

 

2019

Segment Adjusted EBITDA:

 

 

 

Intrastate transportation and storage

$

203

 

 

$

235

 

Interstate transportation and storage

425

 

 

442

 

Midstream

530

 

 

411

 

NGL and refined products transportation and services

762

 

 

667

 

Crude oil transportation and services

631

 

 

726

 

Investment in Sunoco LP

189

 

 

192

 

Investment in USAC

104

 

 

104

 

All other

22

 

 

35

 

Total Segment Adjusted EBITDA

$

2,866

 

 

$

2,812

 

 
 

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

 

Three Months Ended

September 30,

 

2020

 

2019

Natural gas transported (BBtu/d)

12,185

 

 

12,560

 

Withdrawals from storage natural gas inventory (BBtu)

10,315

 

 

 

Revenues

$

654

 

 

$

764

 

Cost of products sold

434

 

 

501

 

Segment margin

220

 

 

263

 

Unrealized losses on commodity risk management activities

23

 

 

19

 

Operating expenses, excluding non-cash compensation expense

(42

)

 

(48

)

Selling, general and administrative expenses, excluding non-cash compensation expense

(7

)

 

(7

)

Adjusted EBITDA related to unconsolidated affiliates

7

 

 

7

 

Other

2

 

 

1

 

Segment Adjusted EBITDA

$

203

 

 

$

235

 

 

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


Contacts

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


Read full story here

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.


Contacts

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.


Contacts

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

Base Case ($40-45/bbl Brent)

Average Production

40,000-42,000 boepd

Total 2021 Capital Expenditures

$100-120 million

Development Capital

$60-70 million

Operating Netback1

$210-280 million

Development/Appraisal Wells (Gross)

26-28 wells

Exploration Wells (Gross)

5-6 wells

Total Wells (Gross)

31-34 wells

 

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.

____________________________

1 Assuming $4/bbl Vasconia-Brent differential.

GLOSSARY

Adjusted EBITDA

Adjusted EBITDA is defined as profit for the period before net finance costs, income tax, depreciation, amortization, the effect of IFRS 16, certain non-cash items such as impairments and write-offs of unsuccessful efforts, accrual of share-based payments, unrealized results on commodity risk management contracts and other non-recurring events

 

Adjusted EBITDA per boe

Adjusted EBITDA divided by total boe sales volumes

 

 

Bbl

Barrel

 

 

Boe

Barrels of oil equivalent

 

Boepd

Barrels of oil equivalent per day

 

Bopd

Barrels of oil per day

 

 

D&M

DeGolyer and MacNaughton

 

F&D costs

Finding and development costs, calculated as capital expenditures divided by the applicable net reserves additions before changes in Future Development Capital

 

 

Mboe

Thousand barrels of oil equivalent

 

Mmbo

Million barrels of oil

 

Mmboe

Million barrels of oil equivalent

 

Mcfpd

Thousand cubic feet per day

 

Mmcfpd

Million cubic feet per day

 

Mm3/day

Thousand cubic meters per day

 

NPV10

Present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual rate of 10%

 

Operating netback

Revenue, less production and operating costs (net of depreciation charges and accrual of stock options and stock awards, the effect of IFRS 16), selling expenses, and realized results on commodity risk management contracts and other non-recurring events. Operating Netback is equivalent to Adjusted EBITDA net of cash expenses included in Administrative, Geological and Geophysical and Other operating costs

 

PRMS

Petroleum Resources Management System

 

 

SPE

Society of Petroleum Engineers

 

 

WI

Working Interest

 

 

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.


Contacts

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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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.

_____________

(1)

The Partnership presents both GAAP and non-GAAP financial measures in this press release to assist in understanding the Partnership’s liquidity and ability to fund distributions. See “Non-GAAP Financial Measures” on page 4 and reconciliations of Net Cash Provided by Operating Activities, the most directly comparable GAAP measure, to Adjusted EBITDA and Distributable Cash Flow on page 10 of this press release.

USD Partners LP
Consolidated Statements of Operations
For the Three and Nine Months Ended September 30, 2020 and 2019
(unaudited)
 

For the Three Months Ended

 

For the Nine Months Ended

September 30,

 

September 30,

 

2020

 

 

 

2019

 

 

 

2020

 

 

 

2019

 

(in thousands)
Revenues
Terminalling services

$

28,905

 

$

23,709

 

$

75,449

 

$

63,437

 

Terminalling services — related party

 

1,041

 

 

4,459

 

 

8,929

 

 

15,622

 

Fleet leases — related party

 

984

 

 

984

 

 

2,951

 

 

2,951

 

Fleet services

 

51

 

 

50

 

 

152

 

 

158

 

Fleet services — related party

 

227

 

 

227

 

 

682

 

 

682

 

Freight and other reimbursables

 

64

 

 

272

 

 

750

 

 

973

 

Freight and other reimbursables — related party

 

65

 

 

193

 

 

66

 

 

254

 

Total revenues

 

31,337

 

 

29,894

 

 

88,979

 

 

84,077

 

Operating costs
Subcontracted rail services

 

2,300

 

 

3,689

 

 

8,433

 

 

10,953

 

Pipeline fees

 

5,936

 

 

5,411

 

 

17,678

 

 

15,374

 

Freight and other reimbursables

 

129

 

 

465

 

 

816

 

 

1,227

 

Operating and maintenance

 

2,299

 

 

2,481

 

 

7,944

 

 

8,202

 

Operating and maintenance — related party

 

2,102

 

 

2,471

 

 

6,194

 

 

2,471

 

Selling, general and administrative

 

2,510

 

 

2,940

 

 

8,310

 

 

8,139

 

Selling, general and administrative — related party

 

1,735

 

 

1,406

 

 

5,563

 

 

6,081

 

Goodwill impairment loss

 

 

 

 

 

33,589

 

 

 

Depreciation and amortization

 

5,430

 

 

5,300

 

 

16,055

 

 

15,317

 

Total operating costs

 

22,441

 

 

24,163

 

 

104,582

 

 

67,764

 

Operating income (loss)

 

8,896

 

 

5,731

 

 

(15,603

)

 

16,313

 

Interest expense

 

2,045

 

 

3,005

 

 

7,040

 

 

9,174

 

Loss associated with derivative instruments

 

1,200

 

 

220

 

 

4,405

 

 

1,966

 

Foreign currency transaction loss (gain)

 

(246

)

 

35

 

 

812

 

 

237

 

Other income, net

 

(33

)

 

(49

)

 

(876

)

 

(52

)

Income (loss) before income taxes

 

5,930

 

 

2,520

 

 

(26,984

)

 

4,988

 

Provision for (benefit from) income taxes

 

(307

)

 

414

 

 

(626

)

 

612

 

Net income (loss)

$

6,237

 

$

2,106

 

$

(26,358

)

$

4,376

 

 
USD Partners LP
Consolidated Statements of Cash Flows
For the Three and Nine Months Ended September 30, 2020 and 2019
(unaudited)
 
For the Three Months Ended For the Nine Months Ended
September 30, September 30,

 

2020

 

 

2019

 

 

2020

 

 

2019

 

Cash flows from operating activities: (in thousands)
Net income (loss)

$

6,237

 

$

2,106

 

$

(26,358

)

$

4,376

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization

 

5,430

 

 

5,300

 

 

16,055

 

 

15,317

 

Loss associated with derivative instruments

 

1,200

 

 

220

 

 

4,405

 

 

1,966

 

Settlement of derivative contracts

 

(342

)

 

 

 

(631

)

 

1

 

Unit based compensation expense

 

1,644

 

 

1,537

 

 

4,909

 

 

4,533

 

Deferred income taxes

 

(722

)

 

104

 

 

(1,263

)

 

(299

)

Other

 

208

 

 

208

 

 

622

 

 

915

 

Goodwill impairment loss

 

 

 

 

 

33,589

 

 

 

Changes in operating assets and liabilities:
Accounts receivable

 

202

 

 

1,704

 

 

892

 

 

1,511

 

Accounts receivable – related party

 

(12

)

 

(383

)

 

(758

)

 

(1,054

)

Prepaid expenses and other assets

 

268

 

 

1,546

 

 

(1,303

)

 

72

 

Other assets – related party

 

(389

)

 

(369

)

 

(899

)

 

(329

)

Accounts payable and accrued expenses

 

536

 

 

(2,463

)

 

(609

)

 

(411

)

Accounts payable and accrued expenses – related party

 

9

 

 

2,472

 

 

(78

)

 

2,429

 

Deferred revenue and other liabilities

 

2,372

 

 

2,661

 

 

6,218

 

 

5,590

 

Deferred revenue – related party

 

(7

)

 

5

 

 

(1,031

)

 

(462

)

Net cash provided by operating activities

 

16,634

 

 

14,648

 

 

33,760

 

 

34,155

 

Cash flows from investing activities:
Additions of property and equipment

 

(18

)

 

(4,395

)

 

(395

)

 

(7,072

)

Net cash used in investing activities

 

(18

)

 

(4,395

)

 

(395

)

 

(7,072

)

Cash flows from financing activities:
Distributions

 

(3,183

)

 

(10,477

)

 

(17,020

)

 

(30,994

)

Payments for deferred financing costs

 

 

 

 

 

 

 

(7

)

Vested Phantom Units used for payment of participant taxes

 

(1

)

 

(5

)

 

(1,789

)

 

(1,826

)

Proceeds from long-term debt

 

2,000

 

 

8,000

 

 

12,000

 

 

28,000

 

Repayments of long-term debt

 

(11,000

)

 

(8,000

)

 

(23,000

)

 

(21,000

)

Other financing activities

 

 

 

 

 

 

 

(13

)

Net cash used in financing activities

 

(12,184

)

 

(10,482

)

 

(29,809

)

 

(25,840

)

Effect of exchange rates on cash

 

(145

)

 

(108

)

 

293

 

 

497

 

Net change in cash, cash equivalents and restricted cash

 

4,287

 

 

(337

)

 

3,849

 

 

1,740

 

Cash, cash equivalents and restricted cash – beginning of period

 

10,246

 

 

14,460

 

 

10,684

 

 

12,383

 

Cash, cash equivalents and restricted cash – end of period

$

14,533

 

$

14,123

 

$

14,533

 

$

14,123

 

 
 
USD Partners LP
Consolidated Balance Sheets
(unaudited)
 

September 30,

 

December 31,

 

2020

 

 

 

2019

 

ASSETS (in thousands)
Current assets
Cash and cash equivalents

$

6,928

 

$

3,083

 

Restricted cash

 

7,605

 

 

7,601

 

Accounts receivable, net

 

4,346

 

 

5,313

 

Accounts receivable — related party

 

2,508

 

 

1,778

 

Prepaid expenses

 

1,529

 

 

1,915

 

Other current assets

 

1,189

 

 

954

 

Other current assets — related party

 

35

 

 

343

 

Total current assets

 

24,140

 

 

20,987

 

Property and equipment, net

 

139,745

 

 

147,737

 

Intangible assets, net

 

64,644

 

 

74,099

 

Goodwill

 

 

 

33,589

 

Operating lease right-of-use assets

 

10,956

 

 

11,804

 

Other non-current assets

 

3,571

 

 

1,335

 

Other non-current assets — related party

 

1,227

 

 

15

 

Total assets

$

244,283

 

$

289,566

 

 
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued expenses

$

2,214

 

$

3,087

 

Accounts payable and accrued expenses — related party

 

384

 

 

465

 

Deferred revenue

 

5,607

 

 

6,104

 

Deferred revenue — related party

 

410

 

 

1,482

 

Operating lease liabilities, current

 

5,371

 

 

4,649

 

Other current liabilities

 

5,495

 

 

3,150

 

Total current liabilities

 

19,481

 

 

18,937

 

Long-term debt, net

 

207,273

 

 

217,651

 

Deferred income tax liabilities, net

 

10

 

 

458

 

Operating lease liabilities, non-current

 

5,685

 

 

7,386

 

Other non-current liabilities

 

12,111

 

 

4,078

 

Total liabilities

 

244,560

 

 

248,510

 

Commitments and contingencies
Partners’ capital
Common units

 

(1,070

)

 

61,013

 

Subordinated units

 

 

 

(22,597

)

General partner units

 

1,836

 

 

2,767

 

Accumulated other comprehensive loss

 

(1,043

)

 

(127

)

Total partners’ capital

 

(277

)

 

41,056

 

Total liabilities and partners’ capital

$

244,283

 

$

289,566

 

 
USD Partners LP
GAAP to Non-GAAP Reconciliations
For the Three and Nine Months Ended September 30, 2020 and 2019
(unaudited)
 

For the Three Months Ended

 

For the Nine Months Ended

September 30,

 

September 30,

 

2020

 

 

 

2019

 

 

 

2020

 

 

 

2019

 

(in thousands)
 
Net cash provided by operating activities

$

16,634

 

$

14,648

 

$

33,760

 

$

34,155

 

Add (deduct):
Amortization of deferred financing costs

 

(208

)

 

(208

)

 

(622

)

 

(865

)

Deferred income taxes

 

722

 

 

(104

)

 

1,263

 

 

299

 

Changes in accounts receivable and other assets

 

(69

)

 

(2,498

)

 

2,068

 

 

(200

)

Changes in accounts payable and accrued expenses

 

(545

)

 

(9

)

 

687

 

 

(2,018

)

Changes in deferred revenue and other liabilities

 

(2,365

)

 

(2,666

)

 

(5,187

)

 

(5,128

)

Interest expense, net

 

2,036

 

 

2,983

 

 

7,004

 

 

9,133

 

Provision for (benefit from) income taxes

 

(307

)

 

414

 

 

(626

)

 

612

 

Foreign currency transaction loss (gain) (1)

 

(246

)

 

35

 

 

812

 

 

237

 

Other income

 

 

 

(27

)

 

 

 

(69

)

Non-cash deferred amounts (2)

 

(16

)

 

1,435

 

 

1,540

 

 

1,545

 

Adjusted EBITDA

 

15,636

 

 

14,003

 

 

40,699

 

 

37,701

 

Add (deduct):
Cash paid for income taxes

 

(190

)

 

(297

)

 

(623

)

 

(904

)

Cash paid for interest

 

(1,880

)

 

(3,045

)

 

(6,837

)

 

(8,860

)

Maintenance capital expenditures

 

(16

)

 

(131

)

 

(130

)

 

(176

)

Distributable cash flow

$

13,550

 

$

10,530

 

$

33,109

 

$

27,761

 

(1)

Represents foreign exchange transaction amounts associated with activities between the Partnership's U.S. and Canadian subsidiaries.

(2)

Represents the change in non-cash contract assets and liabilities associated with revenue recognized at blended rates based on tiered rate structures in certain of the Partnership's customer contracts and deferred revenue associated with deficiency credits that are expected to be used in the future prior to their expiration. Amounts presented are net of the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue.
 

Contacts

Adam Altsuler
Senior Vice President, Chief Financial Officer
(281) 291-3995
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Jennifer Waller
Director, Financial Reporting and Investor Relations
(832) 991-8383
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Read full story here

LONDON--(BUSINESS WIRE)--#FrackingWaterTreatmentMarket--The fracking water treatment market is expected to grow by USD 1.67 billion during 2020-2024, expanding at a CAGR of over 5%. The report also throws light on the impact of the COVID-19 pandemic on the market and the new opportunities and challenges market players can expect. The impact can be expected to be significant in the first quarter but gradually lessen in subsequent quarters – with a limited impact on the full-year economic growth. The report offers a detailed analysis of the impact of the COVID-19 pandemic on the market in optimistic, probable, and pessimistic forecast scenarios. - Download Free Sample Report on Pandemic Recovery Analysis



Fracking Water Treatment Market: Rise in Demand for Crude Oil and Natural Gas to Drive Growth

The rise in demand for crude oil and natural gas is driving the demand for fracking water treatment. The high demand for oil and gas is likely to enhance the E&P activities of crude oil, which, in turn, will augment offshore and onshore oil and gas projects. These factors are expected to increase the demand for hydraulic fracturing as well as water treatment equipment, driving the market growth. The fracking water treatment market size is projected to grow during the forecast period.

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As per Technavio, the shifting focus toward natural gas vehicles (NGVs) will have a positive impact on the market and contribute to its growth significantly over the forecast period. This research report also analyzes other significant trends and market drivers that will influence market growth over 2020-2024.

Fracking Water Treatment Market: Shifting Focus Toward Natural Gas Vehicles (NGVs)

The shifting focus toward natural gas vehicles (NGVs) is one of the emerging fracking water treatment market trends that will influence market growth. Natural gas vehicles are alternative fuel-based vehicles, which use natural gas or liquified natural gas for their operation. The fuel used in this vehicle is cost-effective and clean, which increases the demand for these vehicles. The high demand for natural gas increases the demand for oil and gas E&P activities, in turn, driving the growth of the fracking water treatment market growth.

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Fracking Water Treatment Market: Segmentation Analysis

This market research report segments the fracking water treatment market by Application (Treatment and recycle and Deep well injection) and Geographic Landscape (APAC, Europe, MEA, North America, and South America).

North America accounted for the largest fracking water treatment market share in 2019, and the region will offer several growth opportunities to market vendors during the forecast period. The growing focus of governments in countries such as the US and Canada on the hydraulic fracturing process of oil and gas will significantly influence fracking water treatment market growth in this region. The US and Canada are the key markets for fracking water treatment in North America. Market growth in this region will be slower than the growth of the market in APAC and South America.

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Market Challenges

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  • Vendor classification
  • Market positioning of vendors
  • Competitive scenario

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Permit clears the way for construction to begin

ORANGE, Conn.--(BUSINESS WIRE)--$AGR--AVANGRID, Inc. (NYSE: AGR), a leading sustainable energy company, announced today that the U.S. Army Corps of Engineers has granted approval to the New England Clean Energy Connect (NECEC) Clean Energy Corridor. The NECEC is a renewable energy project being built by AVANGRID to bring hydropower from Quebec to Maine and other parts of New England.

“The Army Corps permit is a significant milestone because it clears the way for construction to begin in the coming weeks,” said AVANGRID President, Robert Kump. “We are excited to start construction on this critical renewable energy project so we can begin to deliver the numerous benefits of NECEC including new local jobs, significant reduction in greenhouse gas emissions, millions of dollars in economic investment and incentives for Maine, and lower energy prices for all of New England. The NECEC is good for Mainers, good for our economy and good for our environment.”

“The NECEC is projected to inject more than $570 million into Maine’s economy and this project will ensure steady work for Mainers in a time of great economic uncertainty,” continued Kump.

“We have already announced more than $300 million worth of contracts that provide much needed jobs and investment in the state and job fairs will be held across Maine this Fall to fill many of the 1600 positions that will be created by this project.”

Following more than three years of extremely rigorous and thorough review and approvals for the project which examined environmental, economic and social impacts, the Army Corps permit is the latest in a series of permits granted by independent regulatory bodies at the state and federal level. All of the regulatory reviews at the state and federal have concluded that the Clean Energy Corridor is environmentally and economically beneficial and good for Maine and New England. The project previously received permits from the Maine Public Utilities Commission, the Maine Land Use Planning Commission, and the Maine Department of Environmental Protection. In addition to municipal level permitting, the remaining required permit for the project is the Presidential Permit from the US Department of Energy, which is required to construct the cross-border transmission component of the line to Quebec.

ABOUT THE NECEC PROJECT

The New England Clean Energy Connect (NECEC) is a $950 million investment that will deliver 1,200 megawatts of renewable hydropower to the New England energy grid in Lewiston, Maine. All of the costs will be paid for by Massachusetts electric customers. Once built, the NECEC will be New England’s largest source of renewable energy, representing a fundamental shift away from fossil fuels while simultaneously lowering energy costs in Maine and New England.

The 145-mile transmission line will be built on land owned or controlled by Central Maine Power. The 53 miles of new corridor on working forest land will use a new clearing technique of tapered vegetation; the remaining two-thirds of the project follows existing power lines created for the state’s hydroelectric industry almost a century ago.

The project will create more than 1,600 good-paying jobs during the two-and-a-half-year construction period and provide $200 million in upgrades to Maine’s energy grid, making Maine’s electricity service more reliable. The NECEC will allow more producers of renewable energy in Maine to get their energy on the grid, and because the corridor project will use clean hydropower, it will reduce the use of fossil fuels, cutting three million metric tons of harmful emissions each year.

For more information about the New England Clean Energy Connect, please visit our website at https://www.necleanenergyconnect.org/

About AVANGRID: AVANGRID, Inc. (NYSE: AGR) is a leading, sustainable energy company with approximately $36 billion in assets and operations in 24 U.S. states. With headquarters in Orange, Connecticut, AVANGRID has two primary lines of business: Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving more than 3.3 million customers in New York and New England. Avangrid Renewables owns and operates a portfolio of renewable energy generation facilities across the United States. AVANGRID employs approximately 6,600 people. AVANGRID supports the U.N.’s Sustainable Development Goals and was named among the World’s Most Ethical Companies in 2019 and 2020 by the Ethisphere Institute. For more information, visit www.avangrid.com.


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LONDON--(BUSINESS WIRE)--#GlobalNMethyl2PyrrolidoneMarket--The global N-methyl-2-pyrrolidone market size is expected to grow by USD 388.99 million during 2020-2024, progressing at a CAGR of over 5% during the forecast period. Download latest version with COVID-19 analysis Free Sample Report



The high demand from APAC is one of the major factors propelling market growth. However, factors such as toxic effects pertaining to the use of N-methyl-2-pyrrolidone will hamper the market growth.

The demand for N-methyl-2-pyrrolidone is increasing due to growth of the automotive industry, as the compound is extensively used in batteries and circuits. The rising adoption rate of electric vehicles in developing countries such as China and India will further boost the demand for N-methyl-2-pyrrolidone in APAC, which is a significant market share holder in terms of geography. Technavio’s market research report identifies that the growth in the automotive industry will be one of the primary growth drivers for the global N-methyl-2-pyrrolidone market until 2024. Also, numerous other end-user industries such as paints and coating, electronics, and pharmaceutical, are adopting N-methyl-2-pyrrolidone due to rapid urbanization, growing population, the increasing personal disposable income, and the booming construction industry.

More details: www.technavio.com/report/n-methyl-2-pyrrolidone-market-industry-analysis

Global N-Methyl-2-Pyrrolidone Market: Application Landscape

N-methyl-2-pyrrolidone is mainly used as a solvent for extraction in the petrochemical industry. Since the downstream or refining process of petroleum crude oil and the purification of natural gas is growing, the demand for N-methyl-2-pyrrolidone has increased exponentially. Therefore, the market growth by the petrochemical industry segment will be significant during the forecast period.

Global N-Methyl-2-Pyrrolidone Market: Geographic Landscape

APAC was the largest N-methyl-2-pyrrolidone market in 2019, and the region will offer several growth opportunities to market vendors during the forecast period. The rising investment in industrial activities coupled with the changing favorable FDI policies in APAC countries will significantly drive N-methyl-2-pyrrolidone market growth in this region over the forecast period. 46% of the market’s growth will originate from APAC during the forecast period. China, India, and Japan are the key markets for N-methyl-2-pyrrolidone in APAC. Market growth in this region will be faster than the growth of the market in other regions.

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Companies Covered

  • Abtonsmart Chemicals (Group) Co. Ltd.
  • Ashland Global Holdings Inc.
  • BASF SE
  • BYN Chemical Co. Ltd.
  • DuPont de Nemours Inc.
  • Eastman Chemical Co.
  • Hefei TNJ Chemical Industry Co. Ltd.
  • LyondellBasell Industries NV
  • Mitsubishi Chemical Corp.
  • Zhejiang Realsun Chemical Co. Ltd. 

What our reports offer:

  • Market share assessments for the regional and country-level segments
  • Strategic recommendations for the new entrants
  • Covers market data for 2019, 2020, till 2024
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  • Strategic recommendations in key business segments based on the market estimations
  • Competitive landscaping mapping the key common trends
  • Company profiling with detailed strategies, financials, and recent developments
  • Supply chain trends mapping the latest technological advancements

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N-Methyl-2-Pyrrolidone Market 2020-2024: Key Highlights

  • CAGR of the market during the forecast period 2020-2024
  • Detailed information on factors that will assist in n-methyl-2-pyrrolidone market growth during the next five years
  • Estimation of the n-methyl-2-pyrrolidone market size and its contribution to the parent market
  • Predictions on upcoming trends and changes in consumer behavior
  • The growth of the n-methyl-2-pyrrolidone market
  • Analysis of the market’s competitive landscape and detailed information on vendors
  • Comprehensive details of factors that will challenge the growth of n-methyl-2-pyrrolidone market, vendors

Table of Contents:

Executive Summary

Market Landscape

  • Market ecosystem
  • Value chain analysis

Market Sizing

  • Market definition
  • Market segment analysis
  • Market size 2019
  • Market outlook: Forecast for 2019 - 2024

Five Forces Analysis

  • Five Forces Analysis
  • Bargaining power of buyers
  • Bargaining power of suppliers
  • Threat of new entrants
  • Threat of substitutes
  • Threat of rivalry
  • Market condition

Market Segmentation by Application

  • Market segments
  • Comparison by Application
  • Oil and gas - Market size and forecast 2019-2024
  • Pharmaceuticals - Market size and forecast 2019-2024
  • Electronics - Market size and forecast 2019-2024
  • Paints and coatings - Market size and forecast 2019-2024
  • Others - Market size and forecast 2019-2024
  • Market opportunity by Application

Customer landscape

Geographic Landscape

  • Geographic segmentation
  • Geographic comparison
  • APAC - Market size and forecast 2019-2024
  • Europe - Market size and forecast 2019-2024
  • North America - Market size and forecast 2019-2024
  • MEA - Market size and forecast 2019-2024
  • South America - Market size and forecast 2019-2024
  • Key leading countries
  • Market opportunity by geography
  • Market drivers
  • Market challenges
  • Market trends

Vendor Landscape

  • Vendor landscape
  • Landscape disruption

Vendor Analysis

  • Vendors covered
  • Market positioning of vendors
  • Abtonsmart Chemicals (Group) Co. Ltd.
  • Ashland Global Holdings Inc.
  • BASF SE
  • BYN Chemical Co. Ltd.
  • DuPont de Nemours Inc.
  • Eastman Chemical Co.
  • Hefei TNJ Chemical Industry Co. Ltd.
  • LyondellBasell Industries NV
  • Mitsubishi Chemical Corp.
  • Zhejiang Realsun Chemical Co. Ltd.

Appendix

  • Scope of the report
  • Currency conversion rates for US$
  • Research methodology
  • List of abbreviations

About Us

Technavio is a leading global technology research and advisory company. Their research and analysis focuses on emerging market trends and provides actionable insights to help businesses identify market opportunities and develop effective strategies to optimize their market positions. With over 500 specialized analysts, Technavio’s report library consists of more than 17,000 reports and counting, covering 800 technologies, spanning across 50 countries. Their client base consists of enterprises of all sizes, including more than 100 Fortune 500 companies. This growing client base relies on Technavio’s comprehensive coverage, extensive research, and actionable market insights to identify opportunities in existing and potential markets and assess their competitive positions within changing market scenarios.


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HOUSTON--(BUSINESS WIRE)--Cactus, Inc. (NYSE: WHD) (“Cactus” or the “Company”) today announced financial and operating results for the third quarter of 2020.

Third Quarter Highlights

  • Revenue of $59.8 million;
  • Income from operations of $12.6 million;
  • Net income of $10.9 million(1) and diluted earnings per Class A share of $0.13(1);
  • Net income, as adjusted(2) of $9.5 million and diluted earnings per share, as adjusted(2) of $0.13;
  • Adjusted EBITDA(3) and related margin(4) of $24.6 million and 41.1%, respectively;
  • Cash flow from operations of $18.9 million;
  • Reduced 2020 net capital expenditure guidance to between $17.5 and $22.5 million;
  • Cash balance of $273.9 million and no bank debt outstanding as of September 30, 2020; and
  • The Board of Directors declared a quarterly cash dividend of $0.09 per share.

     

Financial Summary

 

Three Months Ended

 

September 30,

 

June 30,

 

September 30,

 

2020

 

2020

 

2019

 

(in thousands)

Revenues

$

59,789

 

 

$

66,548

 

 

$

160,808

 

Income from operations

$

12,556

 

 

$

8,875

 

 

$

47,123

 

Operating income margin

21.0

%

 

13.3

%

 

29.3

%

Net income(1)

$

10,886

 

 

$

9,095

 

 

$

35,833

 

Net income, as adjusted(2)

$

9,517

 

 

$

7,367

 

 

$

36,097

 

Adjusted EBITDA(3)

$

24,550

 

 

$

22,483

 

 

$

58,819

 

Adjusted EBITDA margin(4)

41.1

%

 

33.8

%

 

36.6

%

(1)

Net income during the third quarter of 2020 is inclusive of $1.9 million in expense related to the revaluation of the tax receivable agreement liability. Net income during the second quarter of 2020 is inclusive of $0.9 million in non-routine charges related to severance and $1.3 million in additional income related to the revaluation of the tax receivable agreement liability. Net income during the third quarter of 2019 is inclusive of $4.1 million in additional tax expenses related to the write-off of foreign tax credits and the reduction in expected future state tax benefits.

(2)

Net income, as adjusted and diluted earnings per share, as adjusted are non-GAAP financial measures. These figures assume Cactus, Inc. held all units in Cactus Wellhead, LLC (“Cactus LLC”), its operating subsidiary, at the beginning of the period. Additional information regarding net income, as adjusted and diluted earnings per share, as adjusted and the reconciliation of GAAP to non-GAAP financial measures are in the Supplemental Information tables.

(3)

Adjusted EBITDA is a non-GAAP financial measure. See definition of Adjusted EBITDA and the reconciliation of GAAP to non-GAAP financial measures in the Supplemental Information tables.

(4)

The percentage of Adjusted EBITDA to Revenues.

Scott Bender, President and CEO of Cactus, commented, “The third quarter once again showcased our ability to outperform the U.S. rig count while maintaining strong margins during what we believe was the bottom of the current U.S. industry cycle. Cactus achieved record Product market share(1) of approximately 38% during the third quarter, highlighting the resiliency of our customer base and our track record of winning new customers. I am also pleased to report that Cactus has now generated positive free cash flow in all eleven quarters since going public in early 2018.

Looking to the fourth quarter, we expect further gains in rigs followed and associated market share will benefit our Product business. While the near-term focus for our Rental business will continue to be on returns and margins, we are encouraged by the recent improvement in industry completion activity. We believe that total Company quarterly revenues have bottomed and expect an improvement going forward.”

Mr. Bender concluded, “Cactus has proven its ability to generate significant free cash flow and income through the downcycle. In the same vein, management has also further reduced its full year 2020 net capital expenditure budget. We believe the industry's most pronounced activity decline in decades is behind us and we are now turning our attention to the recovery. This team is excited to see the potential benefits that greater operating leverage provides our business as activity levels increase, both in the U.S. and internationally.”

(1)

Additional information regarding market share and rigs followed is located in the Supplemental Information tables.

Revenue Categories

Product

 

Three Months Ended

 

September 30,

 

June 30,

 

September 30,

 

2020

 

2020

 

2019

 

(in thousands)

Product revenue

$

35,857

 

 

$

40,893

 

 

$

92,582

 

Gross profit

$

15,978

 

 

$

14,931

 

 

$

34,814

 

Gross margin

44.6

%

 

36.5

%

 

37.6

%

Third quarter 2020 product revenue decreased $5.0 million, or 12.3%, sequentially, as sales of wellhead and production related equipment decreased primarily due to lower drilling activity in the U.S., which was partially offset by market share gains. Gross profit increased $1.0 million, or 7.0%, sequentially, with margins increasing 810 basis points driven largely by $5.4 million in credits related to tariff refunds, up from $3.1 million during the second quarter of 2020.

Rental

 

Three Months Ended

 

September 30,

 

June 30,

 

September 30,

 

2020

 

2020

 

2019

 

(in thousands)

Rental revenue

$

9,881

 

 

$

11,535

 

 

$

35,528

 

Gross profit

$

234

 

 

$

860

 

 

$

18,334

 

Gross margin

2.4

%

 

7.5

%

 

51.6

%

Third quarter 2020 rental revenue decreased $1.7 million, or 14.3%, sequentially, as our customers’ level of completion activity was lower during the quarter. Gross profit decreased $0.6 million sequentially and margins decreased 510 basis points due largely to depreciation expense representing a higher percentage of revenue during the period.

Field Service and Other

Three Months Ended

 

September 30,

 

June 30,

 

September 30,

 

2020

 

2020

 

2019

 

(in thousands)

Field service and other revenue

$

14,051

 

 

$

14,120

 

 

$

32,698

 

Gross profit

$

4,728

 

 

$

2,634

 

 

$

7,323

 

Gross margin

33.6

%

 

18.7

%

 

22.4

%

Third quarter 2020 field service and other revenue decreased $0.1 million, or 0.5%, sequentially, as lower customer activity drove a slight decrease in associated billable hours and ancillary services. Gross profit increased $2.1 million, or 79.5%, sequentially, with margins increasing by 1,490 basis points sequentially due to lower depreciation, tooling and payroll-related expenses, improved labor and equipment utilization and the rationalization of the Company’s field service vehicle fleet.

Selling, General and Administrative Expenses (“SG&A”)

SG&A for the third quarter of 2020 was $8.4 million (14.0% of revenues), compared to $8.7 million (13.1% of revenues) for the second quarter of 2020 and $13.3 million (8.3% of revenues) for the third quarter of 2019. The sequential decrease was primarily due to lower payroll expenses.

Liquidity, Capital Expenditures and Other

As of September 30, 2020, the Company had $273.9 million of cash and no bank debt outstanding. Operating cash flow was $18.9 million for the third quarter of 2020. During the third quarter, the Company made dividend payments and associated distributions of $6.8 million. The Company also made tax receivable agreement payments and associated distributions of $22.6 million during the third quarter stemming from 2019 imputed tax liabilities.

Net cash used in investing activities represented a cash inflow of $0.1 million during the third quarter of 2020 as capital expenditures were more than offset by proceeds from the sale of assets. The Company reduced its full year 2020 net capital expenditure guidance to between $17.5 and $22.5 million.

During the third quarter, Cactus recognized $6.0 million in refunds pursuant to tariff exclusions granted by the U.S. Trade Representative. The refunds reduced cost of revenue during the period. As previously disclosed, a majority of the Company's tariff exclusions were not extended past August 2020.

Quarterly Dividend

The Board of Directors (the “Board”) has approved the payment of a cash dividend of $0.09 per share of Class A common stock to be paid on December 17, 2020 to holders of record of Class A common stock at the close of business on November 30, 2020. A corresponding distribution of up to $0.09 per CW Unit has also been approved for holders of CW Units of Cactus Wellhead, LLC.

Conference Call Details

The Company will host a conference call to discuss financial and operational results tomorrow, Thursday, November 5, 2020 at 9:00 a.m. Central Time (10:00 a.m. Eastern Time).

The call will be webcast on Cactus’ website at www.CactusWHD.com. Institutional investors and analysts may participate by dialing (866) 670-2203. International parties may dial (630) 489-9861. The access code is 9195227. Please access the webcast or dial in for the call at least 10 minutes ahead of start time to ensure a proper connection.

An archived webcast of the conference call will be available on the Company’s website shortly after the end of the call.

About Cactus, Inc.

Cactus designs, manufactures, sells and rents a range of highly engineered wellhead and pressure control equipment. Its products are sold and rented principally for onshore unconventional oil and gas wells and are utilized during the drilling, completion and production phases of its customers’ wells. In addition, it provides field services for all its products and rental items to assist with the installation, maintenance and handling of the wellhead and pressure control equipment. Cactus operates service centers in the United States, which are strategically located in the key oil and gas producing regions, including the Permian, SCOOP/STACK, Marcellus, Utica, Haynesville, Eagle Ford and Bakken, among other areas, and in Eastern Australia.

Cautionary Statement Concerning Forward-Looking Statements

Certain statements contained in this press release constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to risks, uncertainties and other factors, many of which are outside of Cactus’ control, that could cause actual results to differ materially from the results discussed in the forward-looking statements.

Forward-looking statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” “potential,” “will,” “hope” or other similar words and include the Company’s expectation of future performance contained herein. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. You are cautioned not to place undue reliance on any forward-looking statements, which can be affected by assumptions used or by known risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other factors noted in the Company’s Annual Report on Form 10-K, any Quarterly Reports on Form 10-Q and the other documents that the Company files with the Securities and Exchange Commission. The risk factors and other factors noted therein could cause actual results to differ materially from those contained in any forward-looking statement.

Cactus, Inc.

Condensed Consolidated Statements of Income

(unaudited)

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

2020

 

2019

 

2020

 

2019

 

(in thousands, except per share data)

Revenues

 

 

 

 

 

 

 

Product revenue

$

35,857

 

 

$

92,582

 

$

163,781

 

 

$

273,716

 

Rental revenue

 

9,881

 

 

 

35,528

 

 

57,579

 

 

 

113,601

 

Field service and other revenue

 

14,051

 

 

 

32,698

 

 

59,116

 

 

 

100,859

 

Total revenues

 

59,789

 

 

 

160,808

 

 

280,476

 

 

 

488,176

 

 

 

 

 

 

 

 

 

Costs and expenses

 

 

 

 

 

 

 

Cost of product revenue

 

19,879

 

 

 

57,768

 

 

101,976

 

 

 

168,303

 

Cost of rental revenue

 

9,647

 

 

 

17,194

 

 

39,661

 

 

 

54,435

 

Cost of field service and other revenue

 

9,323

 

 

 

25,375

 

 

44,620

 

 

 

79,105

 

Selling, general and administrative expenses

 

8,384

 

 

 

13,348

 

 

30,739

 

 

 

39,268

 

Severance expenses

 

 

 

 

 

 

1,864

 

 

 

 

Total costs and expenses

 

47,233

 

 

 

113,685

 

 

218,860

 

 

 

341,111

 

Income from operations

 

12,556

 

 

 

47,123

 

 

61,616

 

 

 

147,065

 

 

 

 

 

 

 

 

 

Interest income, net

 

218

 

 

 

373

 

 

851

 

 

 

489

 

Other income (expense), net

 

(1,865

)

 

 

558

 

 

(555

)

 

 

(484

)

Income before income taxes

 

10,909

 

 

 

48,054

 

 

61,912

 

 

 

147,070

 

Income tax expense

 

23

 

 

 

12,221

 

 

8,833

 

 

 

22,041

 

Net income

$

10,886

 

 

$

35,833

 

$

53,079

 

 

$

125,029

 

Less: net income attributable to non-controlling interest

 

4,653

 

 

 

16,494

 

 

21,835

 

 

 

57,475

 

Net income attributable to Cactus, Inc.

$

6,233

 

 

$

19,339

 

$

31,244

 

 

$

67,554

 

 

 

 

 

 

 

 

 

Earnings per Class A share - basic

$

0.13

 

 

$

0.41

 

$

0.66

 

 

$

1.53

 

Earnings per Class A share - diluted (a)

$

0.13

 

 

$

0.41

 

$

0.64

 

 

$

1.50

 

 

 

 

 

 

 

 

 

Weighted average shares outstanding - basic

 

47,510

 

 

 

47,095

 

 

47,406

 

 

 

44,260

 

Weighted average shares outstanding - diluted (a)

 

75,622

 

 

 

47,322

 

 

75,427

 

 

 

75,337

 

(a)

Dilution for the three and nine months ended September 30, 2020 includes $4.7 million and $23.2 million, respectively, of additional pre-tax income attributable to non-controlling interest adjusted for a corporate effective tax rate of 25.5%, and 27.9 million weighted average shares of Class B common stock plus the dilutive effect of restricted stock unit awards. Dilution for the three months ended September 30, 2019 excludes 28.0 million shares of Class B common stock as the effect would be anti-dilutive. Dilution for the nine months ended September 30, 2019 includes an additional $60.1 million of pre-tax income attributable to non-controlling interest adjusted for a corporate effective tax rate of 24%, and 30.8 million weighted average shares of Class B common stock plus the dilutive effect of restricted stock unit awards.

Cactus, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

 

 

September 30,

 

December 31,

 

2020

 

2019

 

(in thousands)

Assets

 

 

 

Current assets

 

 

 

Cash and cash equivalents

$

273,941

 

 

$

202,603

 

Accounts receivable, net

40,290

 

 

87,865

 

Inventories

87,702

 

 

113,371

 

Prepaid expenses and other current assets

9,961

 

 

11,044

 

Total current assets

411,894

 

 

414,883

 

 

 

 

 

Property and equipment, net

148,696

 

 

161,748

 

Operating lease right-of-use assets, net

24,167

 

 

26,561

 

Goodwill

7,824

 

 

7,824

 

Deferred tax asset, net

217,659

 

 

222,545

 

Other noncurrent assets

1,248

 

 

1,403

 

Total assets

$

811,488

 

 

$

834,964

 

 

 

 

 

Liabilities and Equity

 

 

 

Current liabilities

 

 

 

Accounts payable

$

15,573

 

 

$

40,957

 

Accrued expenses and other current liabilities

14,565

 

 

22,067

 

Current portion of liability related to tax receivable agreement

8,902

 

 

14,630

 

Finance lease obligations, current portion

4,009

 

 

6,735

 

Operating lease liabilities, current portion

4,948

 

 

6,737

 

Total current liabilities

47,997

 

 

91,126

 

 

 

 

 

Deferred tax liability, net

792

 

 

1,348

 

Liability related to tax receivable agreement, net of current portion

194,616

 

 

201,902

 

Finance lease obligations, net of current portion

2,286

 

 

3,910

 

Operating lease liabilities, net of current portion

19,237

 

 

20,283

 

Total liabilities

264,928

 

 

318,569

 

 

 

 

 

Equity

546,560

 

 

516,395

 

Total liabilities and equity

$

811,488

 

 

$

834,964

 

Cactus, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)

 

 

Nine Months Ended September 30,

 

2020

 

2019

 

(in thousands)

Cash flows from operating activities

 

 

 

Net income

$

53,079

 

 

$

125,029

 

Reconciliation of net income to net cash provided by operating activities

 

 

 

Depreciation and amortization

 

31,262

 

 

 

28,264

 

Deferred financing cost amortization

 

126

 

 

 

126

 

Stock-based compensation

 

6,436

 

 

 

5,257

 

Provision for expected credit losses

 

341

 

 

 

255

 

Inventory obsolescence

 

3,376

 

 

 

1,708

 

(Gain) loss on disposal of assets

 

(1,810

)

 

 

820

 

Deferred income taxes

 

5,182

 

 

 

15,072

 

(Gain) loss from revaluation of liability related to tax receivable agreement

 

555

 

 

 

(558

)

Changes in operating assets and liabilities:

 

 

 

Accounts receivable

 

48,190

 

 

 

(8,326

)

Inventories

 

19,188

 

 

 

(14,513

)

Prepaid expenses and other assets

 

1,127

 

 

 

4,032

 

Accounts payable

 

(23,753

)

 

 

(4,334

)

Accrued expenses and other liabilities

 

(7,607

)

 

 

4,694

 

Payments pursuant to tax receivable agreement

 

(14,207

)

 

 

(9,335

)

Net cash provided by operating activities

 

121,485

 

 

 

148,191

 

 

 

 

 

Cash flows from investing activities

 

 

 

Capital expenditures and other

 

(21,908

)

 

 

(40,526

)

Proceeds from sale of assets

 

5,414

 

 

 

2,811

 

Net cash used in investing activities

 

(16,494

)

 

 

(37,715

)

 

 

 

 

Cash flows from financing activities

 

 

 

Payments on finance leases

 

(4,298

)

 

 

(5,660

)

Dividends paid to Class A common stock shareholders

 

(12,847

)

 

 

 

Distributions to members

 

(15,560

)

 

 

(5,853

)

Repurchase of shares

 

(1,385

)

 

 

(1,529

)

Net cash used in financing activities

 

(34,090

)

 

 

(13,042

)

 

 

 

 

Effect of exchange rate changes on cash and cash equivalents

 

437

 

 

 

(730

)

 

 

 

 

Net increase in cash and cash equivalents

 

71,338

 

 

 

96,704

 

 

 

 

 

Cash and cash equivalents

 

 

 

Beginning of period

 

202,603

 

 

 

70,841

 

End of period

$

273,941

 

 

$

167,545

 

Cactus, Inc. – Supplemental Information

Reconciliation of GAAP to non-GAAP Financial Measures

Net income, as adjusted and diluted earnings per share, as adjusted

(unaudited)

 

Net income, as adjusted and diluted earnings per share, as adjusted are not measures of net income as determined by GAAP. Net income, as adjusted and diluted earnings per share, as adjusted are supplemental non-GAAP financial measures that are used by management and external users of the Company’s consolidated financial statements. Cactus defines net income, as adjusted as net income assuming Cactus, Inc. held all units in Cactus LLC, its operating subsidiary, at the beginning of the period, with the resulting additional income tax expense related to the incremental income attributable to Cactus, Inc. Net income, as adjusted, also includes certain other adjustments described below. Cactus defines diluted earnings per share, as adjusted as net income, as adjusted divided by weighted average shares outstanding, as adjusted. The Company believes this supplemental information is useful for evaluating performance period over period.

 

 

Three Months Ended

 

September 30,

 

June 30,

 

September 30,

 

2020

 

2020

 

2019

 

(in thousands, except per share data)

Net income

$

10,886

 

 

$

9,095

 

 

$

35,833

 

Adjustments:

 

 

 

 

 

Severance expenses, pre-tax (1)

 

 

 

 

857

 

 

 

 

Other non-operating (income) expense, pre-tax (2)

 

1,865

 

 

 

(1,310

)

 

 

(558

)

Income tax expense differential (3)

 

(3,234

)

 

 

(1,275

)

 

 

822

 

Net income, as adjusted

$

9,517

 

 

$

7,367

 

 

$

36,097

 

 

 

 

 

 

 

Diluted earnings per share, as adjusted

$

0.13

 

 

$

0.10

 

 

$

0.48

 

 

 

 

 

 

 

Weighted average shares outstanding, as adjusted (4)

 

75,622

 

 

 

75,367

 

 

 

75,340

 

(1)

Represents non-routine charges related to severance benefits.

(2)

Represents non-cash adjustments for the revaluation of the liability related to the tax receivable agreement.

(3)

Represents the increase or decrease in tax expense as though Cactus, Inc. owned 100% of Cactus LLC at the beginning of the period, calculated as the difference in tax expense recorded during each period and what would have been recorded, adjusted for pre-tax items listed above, based on a corporate effective tax rate of 25.5% on income before income taxes for the three months ended September 30, 2020, 26.0% for the three months ended June 30, 2020 and 24.0% for the three months ended September 30, 2019.

(4)

Reflects 47.5, 47.4, and 47.1 million weighted average shares of basic Class A common stock and 27.9, 27.9 and 28.0 million of additional shares for the three months ended September 30, 2020, June 30, 2020 and September 30, 2019, respectively, as if the weighted average shares of Class B common stock were exchanged and canceled for Class A common stock at the beginning of the period, plus the effect of dilutive securities.

Cactus, Inc. – Supplemental Information

Reconciliation of GAAP to non-GAAP Financial Measures

EBITDA and Adjusted EBITDA

(unaudited)

 

EBITDA and Adjusted EBITDA are not measures of net income as determined by GAAP. EBITDA and Adjusted EBITDA are supplemental non-GAAP financial measures that are used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. Cactus defines EBITDA as net income excluding net interest, income tax and depreciation and amortization. Cactus defines Adjusted EBITDA as EBITDA excluding the other items outlined below.

 

Cactus management believes EBITDA and Adjusted EBITDA are useful because they allow management to more effectively evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to financing methods or capital structure, or other items that impact comparability of financial results from period to period. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or any other measure as determined in accordance with GAAP. The Company’s computations of EBITDA and Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Cactus presents EBITDA and Adjusted EBITDA because it believes they provide useful information regarding the factors and trends affecting the Company’s business.

 

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

June 30,

 

September 30,

 

September 30,

 

2020

 

2020

 

2019

 

2020

 

2019

 

(in thousands)

 

(in thousands)

Net income

$

10,886

 

 

$

9,095

 

 

$

35,833

 

 

$

53,079

 

 

$

125,029

 

Interest income, net

 

(218

)

 

 

(223

)

 

 

(373

)

 

 

(851

)

 

 

(489

)

Income tax expense

 

23

 

 

 

1,313

 

 

 

12,221

 

 

 

8,833

 

 

 

22,041

 

Depreciation and amortization

 

9,762

 

 

 

10,520

 

 

 

10,007

 

 

 

31,262

 

 

 

28,264

 

EBITDA

 

20,453

 

 

 

20,705

 

 

 

57,688

 

 

 

92,323

 

 

 

174,845

 

Severance expenses (1)

 

 

 

 

857

 

 

 

 

 

 

1,864

 

 

 

 

Other non-operating (income) expense (2)

 

1,865

 

 

 

(1,310

)

 

 

(558

)

 

 

555

 

 

 

(558

)

Secondary offering related expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

1,042

 

Stock-based compensation

 

2,232

 

 

 

2,231

 

 

 

1,689

 

 

 

6,436

 

 

 

5,257

 

Adjusted EBITDA

$

24,550

 

 

$

22,483

 

 

$

58,819

 

 

$

101,178

 

 

$

180,586

 

(1)

Represents non-routine charges related to severance benefits.

(2)

Represents non-cash adjustments for the revaluation of the liability related to the tax receivable agreement.

Cactus, Inc. – Supplemental Information

Depreciation and Amortization by Category

(unaudited)

 

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

June 30,

 

September 30,

 

September 30,

 

2020

 

2020

 

2019

 

2020

 

2019

 

(in thousands)

 

(in thousands)

Cost of product revenue

$

802

 

 

$

863

 

 

$

884

 

 

$

2,693

 

 

$

2,411

 

Cost of rental revenue

6,936

 

 

7,121

 

 

6,384

 

 

21,399

 

 

17,867

 

Cost of field service and other revenue

1,803

 

 

2,286

 

 

2,558

 

 

6,474

 

 

7,486

 

Selling, general and administrative expenses

221

 

 

250

 

 

181

 

 

696

 

 

500

 

Total depreciation and amortization

$

9,762

 

 

$

10,520

 

 

$

10,007

 

 

$

31,262

 

 

$

28,264

 

Cactus, Inc. – Supplemental Information

Estimated Market Share

(unaudited)

 

Market share represents the average number of active U.S. onshore rigs Cactus followed (which Cactus defines as the number of active U.S. onshore drilling rigs to which it was the primary provider of wellhead products and corresponding services during drilling) as of mid-month for each of the three months in the applicable quarter divided by the Baker Hughes U.S. onshore rig count quarterly average. Cactus believes that comparing the total number of active U.S. onshore rigs to which it was providing its products and services at a given time to the number of active U.S. onshore rigs during the same period provides Cactus with a reasonable approximation of its market share with respect to wellhead products sold and the corresponding services it provides.

 

 

Three Months Ended

 

September 30,

 

June 30,

 

September 30,

 

2020

 

2020

 

2019

Cactus U.S. onshore rigs followed

91

 

 

112

 

 

256

 

Baker Hughes U.S. onshore rig count quarterly average

240

 

 

378

 

 

894

 

Market share

37.9

%

 

29.6

%

 

28.6

%


Contacts

Cactus, Inc.
John Fitzgerald, 713-904-4655
Director of Corporate Development and Investor Relations
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Read full story here

DUBLIN--(BUSINESS WIRE)--The "Energy Transition and 'Green Agenda' in Russia: Fashion or Hard Reality?" report has been added to ResearchAndMarkets.com's offering.


The "green agenda" has for years now marched victoriously across the planet, changing the political and economic landscape of the contemporary world ever more radically. The "green wind" has now reached Russia too. There are several aspects at once here.

First of all, this concerns relations with Western Europe where Russia's main energy exports flow. Europe's Green Deal promises serious problems to the Russian supply of hydrocarbons. Carbon tax border adjustments are already looming on the horizon. But export is not the only point.

Demands are heard more and more loudly in Russia that the state should support the development of a low-carbon economy and fit into the general trend: expand subsidisation for renewable energy, encourage energy saving, step up the fight against CO2 emissions.

You will learn from the report answers to the following questions:

  • What is President Putin's position on climate?
    • What was Russia's goal in joining the Paris Agreement?
  • Role of the presidential administration informing the "green agenda"
    • Activities of the presidential adviser on climate and the Interdepartmental Working Group on Climate
  • Position of government regulators
    • Key figures responsible for climate in the Economic Development Ministry, Natural Resources Ministry, Energy Ministry, Industry and Trade Ministry, and other government ministries and agencies
    • System of climate policy-making in Russia
  • Role of the expert community in promoting economic aspects
  • Corporate lobbyists for the "green agenda"
    • Manufacturers of equipment for renewable energy and energy saving
    • Companies believing themselves to be manufacturers of green products
  • Oil and gas corporations and pressure concerning climate: how to organise defence?
  • A medium-term forecast

Key Topics Covered:

1. Introduction

2. Authorities and the 'Green Agenda'

  • Vladimir Putin's Attitude towards the Climate Issue
  • Role of the Administration of the Russian President in Forming the 'Green Agenda'
  • Operation of the Expert Panel of the Interdepartmental Working Group on Climate
  • Role of Government Regulators
  • Influence of the Expert and Research Community on the Position of Authorities

3. Business and the 'Green Agenda'

  • Renewable Energy in the Russian Version of Energy Transition
  • Reporting as an Instrument for Promoting the "Green Agenda"
  • Corporate Lobbyists for the 'Green Agenda'

4. 'Green Agenda' in the Operations of Oil and Gas Companies

  • Rosneft
  • Gazprom Neft
  • Lukoil
  • Tatneft
  • Surgutneftegas
  • Gazprom
  • Novatek

5. Conclusion

For more information about this report visit https://www.researchandmarkets.com/r/mgi9xe


Contacts

ResearchAndMarkets.com
Laura Wood, Senior Press Manager
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For U.S./CAN Toll Free Call 1-800-526-8630
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Company to Showcase Strategic Value Proposition and Long-Term Financial Growth Targets

WALL, N.J.--(BUSINESS WIRE)--New Jersey Resources (NYSE: NJR) today announced the company will host a virtual Analyst Day on Monday, November 30, 2020 at 8:30 a.m. Eastern time. NJR’s senior leadership team will discuss the company’s strategic value proposition and long-term financial growth targets, as well as its year-end fiscal 2020 earnings results.


Scheduled speakers include:

  • Steve Westhoven, President and Chief Executive Officer
  • Patrick Migliaccio, Senior Vice President and Chief Financial Officer
  • Amy Cradic, Senior Vice President and Chief Operating Officer of Non-Utility Businesses, Strategy and External Affairs
  • Mark Kahrer, Vice President, Regulatory Affairs, Marketing and Energy Efficiency
  • Mark Valori, Vice President, Clean Energy Ventures
  • John Bremner, Vice President, Midstream
  • Tim Shea, Vice President, Energy Services

The video webcast of the event, including a question and answer session, will be broadcast via the internet and can be accessed at https://investor.njresources.com/events-and-presentations/default.aspx. For those unable to listen to the broadcast, an archived version will be available at the same location.

About New Jersey Resources

New Jersey Resources (NYSE: NJR) is a Fortune 1000 company that, through its subsidiaries, provides safe and reliable natural gas and clean energy services, including transportation, distribution, asset management and home services. NJR is composed of five primary businesses:

  • New Jersey Natural Gas, NJR’s principal subsidiary, operates and maintains over 7,500 miles of natural gas transportation and distribution infrastructure to serve over half a million customers in New Jersey’s Monmouth, Ocean, Morris, Middlesex and Burlington counties.
  • NJR Clean Energy Ventures invests in, owns and operates solar projects with a total capacity of more than 350 megawatts, providing residential and commercial customers with low-carbon solutions.
  • NJR Energy Services manages a diversified portfolio of natural gas transportation and storage assets and provides physical natural gas services and customized energy solutions to its customers across North America.
  • NJR Midstream serves customers from local distributors and producers to electric generators and wholesale marketers through its ownership of Leaf River Energy Center and the Adelphia Gateway Pipeline Project, as well as our 50 percent equity ownership in the Steckman Ridge natural gas storage facility, and our 20 percent equity interest in the PennEast Pipeline Project.
  • NJR Home Services provides service contracts as well as heating, central air conditioning, water heaters, standby generators, solar and other indoor and outdoor comfort products to residential homes throughout New Jersey.

NJR and its more than 1,100 employees are committed to helping customers save energy and money by promoting conservation and encouraging efficiency through Conserve to Preserve® and initiatives such as The SAVEGREEN Project® and The Sunlight Advantage®. For more information about NJR: www.njresources.com.

Follow us on Twitter @NJNaturalGas.

“Like” us on facebook.com/NewJerseyNaturalGas.


Contacts

Media:
Michael Kinney
732-938-1031
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Investor:
Dennis Puma
732-938-1229
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LONDON--(BUSINESS WIRE)--#GlobalMicrogridMarket--The new microgrid market research from Technavio indicates Positive growth in the short term as the business impact of COVID-19 spreads.



Get detailed insights on the COVID-19 pandemic Crisis and Recovery analysis of the microgrid market. Download free report sample

"One of the primary growth drivers for this market is the increasing government support,” says a senior analyst for Industrials at Technavio.

Governments across the world are supporting the adoption of microgrids due to its strong endurance capability during natural calamities. Microgrid projects are backed by funding benefits in the form of grants from federal and state governments in the US. Increasing government support is a major factor that will fuel the growth of the microgrid market during the forecast period. The New York state R&D authority awarded funds for microgrid projects to be deployed in 83 communities with the help of prize money worth USD 8 million. The Japanese government also estimated a budget of USD 0.5 million per month for developing advanced microgrids to contribute to the development and implementation of microgrids. Such factors will drive microgrid market growth by 2024.

As the markets recover Technavio expects the microgrid market size to grow by USD 18.89 billion during the period 2020-2024.

Microgrid Market Segment Highlights for 2020

  • The microgrid market is expected to post a year-over-year growth rate of 12.34%.
  • Remote microgrids have found applications mostly in villages where grid-connected power is not accessible or is available only for a limited period.
  • The average-sized microgrids used in villages have a capacity of 10 kW. India, Indonesia, Bangladesh, and several countries in Africa and Southeast Asia are the prospective markets for remote microgrids.
  • Market growth in this segment will be slower than the growth of the market in the institutions and campus and military segment.

Regional Analysis

  • 28% of the growth will originate from the North America region.
  • The growing energy-efficient power requirements and the rising need for adopting decentralized power systems will significantly drive microgrid market growth in this region over the forecast period.
  • The US and Canada are the key markets for microgrids in North America. Market growth in this region will be slower than the growth of the market in other regions.

Click here to learn about report detailed analysis and insights on how you can leverage them to grow your business.

Notes:

  • The microgrid market size is expected to accelerate at a CAGR of almost 13% during the forecast period.
  • The microgrid market is segmented by Application (Remote, Institutions and campus, Military, and Others) and Geography (North America, APAC, Europe, South America, and MEA).
  • The market is fragmented due to the presence of many established vendors holding significant market share.
  • The research report offers information on several market vendors, including ABB Ltd., Eaton Corp. Plc, Emerson Electric Co., Exelon Corp., General Electric Co., Honeywell International Inc., Powerhive Inc., S&C Electric Co., Schneider Electric SE, and Siemens AG

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