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FRO - Q1 2017 Presentation

Oil - 30 May 2017 - 7:36am

Please find enclosed the presentation of Frontline Ltd.'s first quarter 2017 results.

Frontline Ltd.

Hamilton, Bermuda

May 30, 2017


This information is subject to the disclosure requirements pursuant to section 5 -12 of the Norwegian Securities Trading Act.



Categories: State

RMP Energy Announces Board of Director Changes

Oil - 30 May 2017 - 7:30am

CALGARY, Alberta, May 30, 2017 (GLOBE NEWSWIRE) -- RMP Energy Inc. (“RMP” or the “Company”) (TSX:RMP) announces the appointment of three (3) new members to its Board of Directors (the "Board"). Jay P. McWilliams, Steven D. Oldham and Dean J.W. Bernhard have been appointed to the Board effective immediately. The Company's Board now consists of Joshua D. Young (Chairman), Jay P. McWilliams, Steven D. Oldham and Dean J.W. Bernhard, of which Messrs. Young, McWilliams and Oldham are independent directors.  RMP is also pleased to announce that Mr. Robert Colcleugh agreed to join the Board as an observer and intends to stand for election at the Company’s next annual shareholders meeting. The Company is in the process of identifying additional qualified individuals to join the Board.

Mr. McWilliams is the Founder and President of LOGOS Resources II, LLC, a premier oil and gas acquisition, development and exploitation company pursuing opportunities in the San Juan basin.  Prior to founding LOGOS, Mr. McWilliams was the lead acquisition engineer at Linn Energy, a Houston-based oil and gas company, where he led approximately $1 billion in successful transactions.  Mr. McWilliams previously held various engineering positions while working for Burlington Resources and Resolute Natural Resources and holds a Bachelor of Science Degree in Chemical Engineering with Honours from New Mexico Tech and an MBA from the Fuqua School of Business at Duke University. 

Mr. Oldham is an independent businessman and private investor with over 15 years of financial management experience in the oilfield service and construction industries.  From 2012 to 2015 he served as Vice President, Treasury and Investor Relations for McDermott International and from 1998 to 2011, he was Vice President and Treasurer for Pride International Inc., an offshore oil drilling company with offices in Houston, Texas until its acquisition by Ensco plc. Prior to joining Pride International, Mr. Oldham was a financial analyst with Salomon Brothers and Bank of America.  Mr. Oldham holds a Bachelors' degree in Business Administration from the University of Texas at Austin and an MBA from the University of Chicago Booth School of Business.

Mr. Bernhard is a Chartered Professional Accountant with 26 years of upstream oil and gas experience and is currently the Vice President, Finance and Chief Financial Officer of RMP. Mr. Bernhard holds a Bachelor of Commerce (Finance degree) from the University of Saskatchewan. Prior to his current role at RMP, Mr. Bernhard served as Vice President, Finance and Chief Financial Officer of Orleans Energy Ltd. between January 2005 and May 2011, at which time Orleans undertook a reverse take-over transaction by RMP. Mr. Bernhard began his career with Amoco Canada Limited and previously worked for Tarragon Oil and Gas Limited, Marathon Oil Canada Limited and E3 Energy Inc., in various financial and accounting capacities.

Mr. Colcleugh is currently the Chief Executive Officer of Beyond Energy Services & Technology Corp., a managed pressure drilling service company based in Calgary, Alberta. He is also a member of the Board of Directors of Tidewater Midstream and Infrastructure Ltd. Prior thereto, he was Managing Director of Investment Banking for Macquarie Capital Markets Canada Ltd. (a division of Macquarie Bank) from 2009 until January 2017. Prior thereto, he was one of the founders of Tristone Capital Inc., a global energy investment banking boutique that was purchased by Macquarie in 2009. Over the last 15 years Mr. Colcleugh has provided financing, mergers, acquisitions and divestiture advisory services to a broad array of energy companies in the domestic Canadian, international, midstream and technology industries. Prior to his involvement in capital markets, he managed Duke Energy’s Power business in Ontario and their capital business in Canada where he deployed the utility’s balance sheet and created structured products around natural gas and power streams for customers. Mr. Colcleugh holds a B.A. in Economics from the University of Western Ontario and a MBA from the University of Western Ontario’s Ivey Business School.

In conjunction therewith, the Company announces that Andrew L. Hogg, James M. Saunders, Craig W. Stewart and Lloyd C. Swift have resigned from RMP’s Board, effective immediately. The Company would like to express its appreciation to these individuals for their many years of service as Board members, providing invaluable stewardship and business acumen throughout their tenure.

RMP Energy Inc. is a Montney-focused crude oil and natural gas producer, based in Calgary, Alberta.  RMP's common shares trade on the Toronto Stock Exchange under the ticker "RMP".  For additional information on the Company, please visit RMP's website at:  www.rmpenergyinc.com.

CONTACT: For more information, please contact: RMP ENERGY INC. Jon Grimwood President (403) 930-6311 jon.grimwood@rmpenergyinc.com Dean Bernhard Vice President, Finance and Chief Financial Officer (403) 930-6304 dean.bernhard@rmpenergyinc.com
Categories: State

Emblem Corp. Enters into Agreements to Acquire Land for Production Capacity Expansion in Preparation for the Adult Recreational Market

Recreation - 30 May 2017 - 7:00am
  • Expected to break ground in Q3 2017 to build the first of three state-of-the-art 100,000 sq. ft. production facilities with an estimated completion date in Q4 2018 providing an expected production capacity of up to 20,000 kilograms  
  • Total aggregate production capacity estimated to exceed 70,000 kilograms per annum once fully built at 300,000 sq. ft.
  • Natural gas infrastructure available to the land expected to allow Emblem to go “off the grid”  and to pursue its objective of becoming one of the lowest cost “closed box” producers in Canada

PARIS, Ontario, May 30, 2017 (GLOBE NEWSWIRE) -- Emblem Corp. (TSXV:EMC) (“Emblem” or the "Company") is pleased to announce that it has agreed to purchase two contiguous parcels of land, aggregating approximately 80 acres of industrially zoned land within very close proximity to the Company’s current production facilities in Paris, Ontario, in preparation for the anticipated demand for cannabis and cannabis derived products stemming from the proposed legalization of adult recreational use in Canada.  The aggregate purchase price for the land is $7.7 million.

The New Production Facilities on Newly Acquired Land

Emblem intends to break ground on the newly acquired land during the third quarter of 2017 to execute on the design and build of its initial 100,000 sq. ft. state-of-the-art facility, with 60,000 sq. ft. dedicated to production and the remaining 40,000 sq. ft. allocated to support services and administrative functions. Once operating at an optimal level, the Company expects this facility to enable the Company to produce up to 20,000 kilograms of dried cannabis, translating to approximately $160.0 million in potential sales based on the Company’s current average selling price of approximately $8.00 per gram (or equivalent derivative product) and production capacity assumptions.

The Company expects to continue its production capacity expansion plans based on two additional 100,000 sq. ft. production modules. Following the completion of the first module, future facilities will have a higher percentage of space dedicated to cultivation. On this basis, the Company anticipates that its total production capacity should reach about 70,000 kilograms per annum, once a total of 300,000 sq. ft. of new production space becomes operational.

Balance Sheet Strength

Emblem currently has approximately $33.0 million of cash on hand and about $34.0 million of “in-the-money” warrants, a portion of which are callable. Through its existing capital structure, the Company expects to be able to complete the first 100,000 sq. ft. production capacity expansion on its newly acquired land in Paris, Ontario without the need to raise additional capital. The Company expects to complete that expansion in time to address the anticipated demand for its dried flower and derivative products in the adult use market proposed to be introduced across Canada.

It is likely that the Company will require additional funding for the construction of its second and third 100,000 sq. ft. production facilities. In the event the Company requires additional funding, the Company will consider a variety of financing options including the application of future free cash flows, debt or the equity markets, at the appropriate time.

Potential Economic Impact

Based on the Company's current analysis and the production and revenue metrics referred to above, the Company expects that annualized production from its first 100,000 sq. ft. facility will reach approximately 20,000 kilograms and will generate revenues from dried flower and derivative products of up to approximately $160.0 million based on the Company’s current average selling price of approximately $8 per gram (or equivalent derivative product price). Once all three production facilities are fully built and operational, the total 300,000 sq. ft. of production facilities is expected to produce approximately 70,000 kilograms of product (or extracted equivalent).

This is in addition to the Company’s expected revenue contribution from its pharmaceutical focused medical cannabis business.

Significance of Land Acquisition Strategy

Emblem is committed to the development of “closed box” indoor production facilities. It is generally recognized that dried flower will constitute the largest portion of the Canadian adult use market. The production of high quality dried flower requires stringent control of both temperature and humidity during the cultivation cycle. The production of high quality dried flower will require licensed producers to make extensive investments in environmental control systems (principally chiller and boiler capacity). Emblem’s closed box architecture will involve extensively insulated, enclosed structures that are expected to allow for the most efficient sizing and lowest capital cost for these environmental control systems relative to the volume of cultivation space. This highly insulated, closed box approach is also expected to result in lower operating costs for those environmental systems.

High quality dried flower also requires sequestration from the outside environment to protect the plant from exposure to contamination from spores and botanical hormones. Emblem’s building design is intended to isolate the cultivation process from exterior hazards.

The totally enclosed structures to be built by Emblem are designed to allow the Company to seek the optimum environmental conditions for consistent cultivation of high quality dried flower product, at scale, and to aim to produce that product at the lowest operating cost.

This production methodology requires access to robust natural gas and electricity infrastructure to support the significant energy demands of large scale, superior quality cannabis production. The land acquired by Emblem provides access to high pressure, high capacity natural gas and high wattage electricity. In addition, in order to aim to become the lowest cost producer possible, Emblem intends to “go off the grid”. The high capacity natural gas connections available to the acquired land will fully support the gas-fired generation of electricity and co-generation of heat and CO2 which are expected to allow Emblem to materially lower its electricity costs and displace costs for heat and CO2.

The acquisition of the expansion land in close proximity to Emblem’s current licensed campus reflects Emblem’s core strategy for serving the Canadian medical and adult use markets, which is to develop its business with a:

  • uniform approach to its closed box production methodology involving consistent architectural and engineering design for all facilities to maximize facility quality and efficiency while minimizing capital cost;
  • common management team for all production, eliminating issues inherent in managing geographically disparate operations; and
  • common cultivation and production staff for all production working under common standard operating procedures to maximize the uniformity and quality of product sold under the Emblem brand.

The land acquisition is expected to allow Emblem to expand its medical cannabis business and, when legal, commence its adult use business without constraints on capacity. It is Emblem’s belief that a “build from within” approach to reaching full capacity will be materially more capital efficient compared to expansion through the acquisition of other licensed producers while avoiding all of the facility rehabilitation, management and personnel integration, and product quality issues over multiple platforms that are inherent in capacity growth through acquisition.

About Emblem

Emblem is licensed under the Access to Cannabis for Medical Purposes Regulations (the “ACMPR”) to cultivate and sell medical marihuana. Emblem carries out its principal activities producing marihuana from its facilities in Paris, Ontario pursuant to the provisions of the ACMPR and the Controlled Drugs and Substances Act (Canada) and its regulations.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

This news release contains certain forward-looking statements and forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian securities laws. All statements other than statements of present or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "anticipate", "achieve", "could", "believe", "plan", "intend", "objective", "continuous", "ongoing", "estimate", "outlook", "expect", "may", "will", "project", "should" or similar words, including negatives thereof, suggesting future outcomes.

In particular, this news release contains forward-looking statements relating to, among other things: (i) the acquisition of the newly acquired land; (ii) the completion of the proposed facilities by the Company; (iii) the ability of the Company to utilize the new facilities to produce additional dried cannabis; (iv) potential sales of dried cannabis produced at the new facilities and the value thereof; (v) the Company's future production capacity; (vi) the availability of additional sources of financing; (vii) the ability of the Company to establish a "closed box"  indoor production facility; (viii) the ability of the Company to produce high quality dried flower; (ix) the benefits associated with the acquisition of the additional land; (x) the intention to grow the business, operations and potential activities of the Company; (xi) receipt of approval from Health Canada to complete such expansion and increase production and sale capacity; and (xii) the anticipated changes to Canadian federal laws regarding adult  use and the business impacts on the Company.

Management of the Company believes the expectations reflected in such forward-looking statements are reasonable as of the date hereof but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Various material factors and assumptions are typically applied in drawing conclusions or making the forecasts or projections set out in forward-looking statements. Those material factors and assumptions are based on information currently available to the Company, including data from publicly available governmental sources as well as from market research and industry analysis and on assumptions based on data and knowledge of this industry which Emblem believes to be reasonable. However, although generally indicative of relative market positions, market shares and performance characteristics, such data is inherently imprecise. While Emblem is not aware of any misstatement regarding any industry or government data presented herein, the medical marijuana industry involves risks and uncertainties and is subject to change based on various factors.

Forward-looking statements are not a guarantee of future performance and are subject to and involve a number of known and unknown risks and uncertainties, many of which are beyond the control of the Company, which may cause the Company's actual performance and results to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to, the risks identified in the Company's filing statement dated November 30, 2016 and in the Company's short form prospectus dated March 16, 2017 both of which have been filed with the Canadian Securities Administrators and available on www.sedar.com. Any forward-looking statements are made as of the date hereof and, except as required by law, the Company assumes no obligation to publicly update or revise such statements to reflect new information, subsequent or otherwise.

This news release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Emblem's prospective results of operations, sales, revenues, funds flow, and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this news release was made as of the date of this document and was provided for the purpose of providing further information about the Company's future business operations. The Company disclaims any intention or obligation to update or revise any FOFI contained in this news release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this news release should not be used for purposes other than for which it is disclosed herein.

CONTACT: For further information contact: Ali Mahdavi Emblem Corp. (416) 962-3300 alimahdavi@emblemcorp.com
Categories: State

Midland States Bancorp, Inc. and Centrue Financial Corporation Announce Election Deadline

Banking - 30 May 2017 - 6:00am

EFFINGHAM, Ill. and OTTAWA, Ill., May 30, 2017 (GLOBE NEWSWIRE) -- Midland States Bancorp, Inc. (NASDAQ:MSBI) (“Midland”) and Centrue Financial Corporation (NASDAQ:CFCB) (“Centrue”) today announced that the election deadline for Centrue shareholders of record to make merger consideration elections in connection with the previously announced merger between Midland and Centrue is 5:00 p.m., Eastern Daylight Time, on June 2, 2017. Centrue shareholders may elect to receive $26.75 in cash, 0.7604 shares of Midland common stock or a combination of $9.3625 in cash and 0.4943 shares of Midland common stock in exchange for each share of Centrue’s common stock, subject to adjustment and proration as provided in the merger agreement.

Centrue shareholders who need a duplicate copy of the election form and letter of transmittal and instructions or who have questions about making an election prior to the election deadline may contact Georgeson LLC, the information agent for the merger, at: Georgeson LLC, 1290 Avenue of the Americas, 9th Floor, New York, NY 10104 or by calling (877) 278-4775.

About Midland States Bancorp, Inc.

Midland States Bancorp, Inc. is a community-based financial holding company headquartered in Effingham, Illinois, and is the sole shareholder of Midland States Bank. Midland had assets of approximately $3.4 billion, and its Midland Wealth Management Group had assets under administration of approximately $1.9 billion as of March 31, 2017.  Midland provides a full range of commercial and consumer banking products and services, merchant credit card services, trust and investment management, and insurance and financial planning services. In addition, commercial equipment leasing services are provided through Heartland Business Credit, and multi-family and healthcare facility FHA financing is provided through Love Funding, Midland’s non-bank subsidiaries. Midland has more than 80 locations across the United States. For additional information, visit www.midlandsb.com or follow Midland on LinkedIn at https://www.linkedin.com/company/midland-states-bank.

About Centrue Financial Corporation

Centrue Financial Corporation is a regional financial services company headquartered in Ottawa, Illinois and devotes special attention to personal service. Centrue serves a market area which extends from the far western and southern suburbs of the Chicago metropolitan area across Central Illinois and metropolitan St. Louis.  Further information about Centrue is available at its website at http://www.centrue.com.

Additional Information

This communication is being made in respect of the merger involving Midland and Centrue. 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.

Midland has filed a registration statement on Form S-4 with the SEC in connection with the proposed transaction. The registration statement includes a proxy statement of Midland and Centrue that also constitutes a prospectus of Midland, which has been sent to the shareholders of each of Midland and Centrue. Shareholders are advised to read the joint proxy statement/prospectus because it contains important information about Midland, Centrue and the proposed transaction. This document and other documents relating to the merger filed by Midland and Centrue can be obtained free of charge from the SEC’s website at www.sec.gov. These documents also can be obtained free of charge by accessing Midland’s website at www.midlandsb.com under “Investors” and then under the “SEC Filings” tab. Alternatively, these documents may be obtained free of charge from Midland upon written request to Midland States Bancorp, Inc., Corporate Secretary, 1201 Network Centre Drive, Effingham, Illinois, 62401 or by calling (217) 342-7321 or emailing corpsec@midlandsb.com, or from Centrue, upon written request to Centrue Financial Corporation, Investor Relations, 122 West Madison Street, Ottawa, Illinois 61350 or by calling (815) 431-8400 or emailing investor.relations@centrue.com.

Participants in this Transaction

Midland, Centrue and certain of their respective directors and executive officers may be deemed to be participants in the solicitation of proxies from shareholders in connection with the proposed transaction under the rules of the SEC. Information about these participants may be found in Midland’s definitive proxy statement relating to its 2017 annual meeting of shareholders filed with the SEC on March 17, 2017 and in Centrue’s Annual Report on Form 10-K filed with the SEC on March 2, 2017. These documents can be obtained free of charge from the sources indicated above. Additional information regarding the interests of these participants is included in the joint proxy statement/prospectus regarding the proposed transaction.

CONTACT: CONTACTS: For Midland: Douglas J. Tucker, Sr. V.P., Corporate Counsel, at dtucker@midlandsb.com or (217) 342-7321 For Centrue: Daniel R. Kadolph, Chief Financial Officer, at daniel.kadolph@centrue.com or (815) 431-2838
Categories: State

Husky to Present Five-Year Growth Plan at Investor Day

Oil - 30 May 2017 - 6:00am

Five-Year Plan Highlights1

Key Metrics20172017 – 2021F CAGR22021FProduction (mboe/day)320 - 3354.8%390-400Funds from operations3 $3.3B9%~$4.8BFree cash flow3$750M12%~$1.2BUpstream operating cost/bbl$14.25 <$12Downstream refining margins/bbl$14.75 >$16Earnings break-even oil price (US WTI)3~$43.60 ~$37Cash break-even oil price (US WTI) 3~$33.50 ~$32Ranges and Targets 2017-2021F Sustaining capital3 Average $1.9B Capital expenditures Average $3.3B Average proved reserve replacement ratio Target >130% Net debt to FFO3 <2x  (1) Based on oil price of $50 US WTI in 2017, $55 in 2018, and $60 in 2019 through 2021. AECO priced at $2.50 Cdn in 2017 and $3.00 thereafter(2) Compound annual growth rate(3) Non-GAAP measures, refer to advisories 

CALGARY, Alberta, May 30, 2017 (GLOBE NEWSWIRE) -- Husky Energy will hold its Investor Day in Toronto today to present a five-year plan expected to grow funds from operations at a compounded rate of nine percent a year.

Husky’s plan includes continued cost structure reductions and provides for returns-focused growth.

“We have transformed Husky to grow profitably in this new, lower commodity price era,” said CEO Rob Peabody. “With a significantly reduced break-even and one of the strongest balance sheets in the industry, we are set to further develop a deep portfolio of investment opportunities that will allow us to compound returns, generate increased free cash flow and return cash to shareholders.”

Under Husky’s plan, funds from operations are expected to grow from about $3.3 billion in 2017 to about $4.8 billion in 2021. Free cash flow is expected to grow at a compound annual growth rate of 12 percent, rising from about $750 million in 2017 to about $1.2 billion in 2021.

“Production will increase steadily over our five-year plan, with funds from operations and free cash flow growing at much higher rates as a result of ongoing reductions in our cost structure,” added Peabody.

As a result of continued cost efficiencies, capital spending guidance for 2017 has been reduced by $100 million to $2.5 - $2.6 billion.

Husky’s Five-Year Plan Highlights:

  • 4.8 percent per year production growth, from about 320,000 – 335,000 barrels of oil equivalent per day (boe/day) in 2017 to 390,000 – 400,000 boe/day in 2021, which includes new thermal oil development at Lloyd, the Tucker Thermal Project, Sunrise, and Asia Pacific offshore gas.
  • 17 percent lower operating costs (to less than $12 per boe) as a result of ongoing investment in lower-cost, longer-life production.
  • Lower sustaining capital requirements per boe – sustaining capital increases at a lower rate than production growth.
  • Growing production and fixed-price gas contracts in Asia Pacific deliver strong netbacks with low volatility.
  • Higher downstream margins from increased heavy oil processing capacity, expanded asphalt capacity, and product sales flexibility.
  • Strong inventory of projects that can deliver at least 10 percent rates of return after tax at $45 US WTI, break even at $35 US WTI.

Two Core Businesses

Husky’s go-forward strategy focuses on two core businesses: an integrated Canada-U.S. upstream and downstream corridor and offshore production in the Asia Pacific and Atlantic regions. Both businesses have strong prospects to generate increased free cash flow over the five-year plan, with built-in measures to mitigate volatility.

Integrated Corridor – North American Upstream and Downstream

Husky has a large and growing inventory of heavy oil thermal projects in the Lloydminster region of Saskatchewan and Alberta, as well as the Tucker Thermal Project near Cold Lake and the Sunrise Energy Project north of Fort McMurray. These projects are physically integrated with the Downstream business, which provides for increased margin capture, secured U.S. market access and free cash flow growth.

Thermal bitumen production at the end of 2016 was approximately 120,000 barrels per day (bbls/day), a 55 percent increase since 2015. Husky expects to add 40,000 bbls/day of new thermal bitumen nameplate capacity over the next five years. A 10,000 bbls/day thermal bitumen project is under construction at Rush Lake 2, and three additional 10,000 bbls/day thermal bitumen projects are progressing in Saskatchewan at Dee Valley, Spruce Lake North and Spruce Lake Central. Husky has identified at least 14 additional Lloyd thermal developments for potential advancement.

Tucker thermal bitumen production is currently averaging about 23,000 bbls/day and with new wells being commissioned, production is expected to ramp up towards 30,000 bbls/day in 2018. At Sunrise, gross production is now about 40,000 bbls/day, with 14 new well pairs in the process of being tied-in and placed on production by the end of 2017.

Supporting this thermal growth is Western Canada production, which is now more than 70 percent gas-weighted. This provides a supply and natural hedge for Husky’s energy requirements at its thermal projects and refineries.

The final leg of the corridor is Husky’s Downstream assets consisting of its storage facilities, Lloydminster Upgrader, asphalt plant and refining capacity in the PADD II district of the U.S. Midwest, which creates processing and marketing options. Husky’s five-year plan includes targeted investments to increase feedstock flexibility, optimize the product slate and increase margin capture:

  • At the Lloydminster Complex, which includes an Upgrader and an asphalt refinery, engineering is progressing on a proposal to double asphalt processing capacity to 60,000 bbls/day.
  • At the Lima, Ohio refinery, the crude oil flexibility project is expected to increase heavy oil processing capacity to 40,000 bbls/day by the end of 2018. It can currently process up to 10,000 bbls/day of heavy crude.
  • At the partner-operated Toledo Refinery, upgrades have increased the amount of high-TAN crude that can be processed to 65,000 bbls/day, accommodating volumes from the Sunrise Energy Project. This has improved margins by about $3 US per barrel for Toledo’s refinery throughput.


Husky currently invests in two offshore production regions – Asia Pacific, offshore China and Indonesia; and Atlantic, offshore Newfoundland and Labrador. Each region provides for high netback production, with robust near-term investment opportunities and the ability to generate immediate free cash flow growth.

Asia Pacific

  • Production from the region is expected to grow about 50 percent over the five-year plan to about 60,000 boe/day, reflecting increasing volumes from fixed-price gas projects offshore Indonesia and the Liwan Gas Project.
  • First gas sales are expected to begin soon at the BD Gas Project in the Madura Strait, with an expected ramp-up to full sales gas rates during the second half of 2017.
  • The MDA-MBH and MDK fields are being developed in tandem and are scheduled for first production in the 2018-2019 timeframe. A plan of development has been approved for the MAC field and additional opportunities are being evaluated.
  • The Company recently signed a production sharing contract for Block 16/25 in the Pearl River Mouth Basin offshore China. Two exploration wells are expected to be drilled on the shallow water block in the 2018 timeframe, in conjunction with two other planned exploration wells at nearby Block 15/33.
  • Negotiations are progressing on a fixed-price sales agreement for the Liuhua 29-1 field. Project sanction is anticipated in the second half of 2017, subject to a final price agreement.


  • Husky and its partners announced they are moving forward with development of the West White Rose Project. The project will use a fixed wellhead platform tied back to the SeaRose floating production, storage and offloading (FPSO) vessel, which will enable the Company to maximize resource recovery. First oil is expected in 2022 and the project is anticipated to achieve gross peak production rate of 75,000 bbls/day (52,500 bbls/day Husky working interest) in 2025.
  • Infill wells continue to extend the life of the main White Rose field by mitigating natural declines. A new development well was completed at South White Rose in the fourth quarter of 2016. It was followed by a new infill well at North Amethyst in the first quarter of 2017, and an additional infill well at White Rose is expected to be brought on production later in 2017.
  •  A new discovery has been made in the White Rose production area at Northwest White Rose. The A-78 exploration well was drilled about 11 kilometres northwest of the SeaRose FPSO in the first quarter of 2017 and delineated a light oil column of more than 100 metres. The discovery continues to be assessed. Husky has a 93.2 percent ownership interest.
  • Drilling has commenced on two additional exploration wells in the Flemish Pass Basin. The Company has a 35 percent working interest in five oil discoveries in the Flemish Pass at Bay du Nord, Mizzen, Harpoon, Bay de Verde and Baccalieu.

2017 Investor Day

Members of Husky's senior management team will meet with investors and analysts today to discuss the Company’s five-year plan. Presentations will be webcast and will be available at www.huskyenergy.com

Location:Civic Ballroom, Sheraton Centre Toronto Hotel 123 Queen St. W, Toronto, Ontario

Presentations begin at 10 a.m. Eastern Time. The webcast may be accessed approximately 10 minutes before the scheduled start time. A webcast archive and transcript will be available for 90 days following the presentation. 

Husky Energy is a Canadian-based integrated energy company. It is headquartered in Calgary, Alberta, Canada and its common shares are publicly traded on the Toronto Stock Exchange under the symbol HSE. More information is available at www.huskyenergy.com


Certain statements in this presentation, including "financial outlook," are forward-looking statements and information (collectively “forward-looking statements”) within the meaning of applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this presentation are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "will likely result", "are expected to", "will continue", "is anticipated", "is targeting", "estimated", "intend", "plan", "projection", "could", "aim", "vision", "goals", "objective", "target", "schedules" and "outlook").  In particular, forward-looking statements in this presentation include, but are not limited to, references to:

  • with respect to the business, operations and results of the Company generally:  the Company’s general strategic plans and growth strategies; forecasted production, funds from operations, free cash flow, upstream operating cost per barrel, downstream refining margins per barrel, earnings break-even oil price and cash break-even oil price by 2021 and range and targets for sustaining capital, capital expenditures, five-year average proved reserve replacement ratio and net debt to funds from operations from 2017 to 2021; forecast production, funds from operations and free cash flow compound annual growth rate from 2017 to 2021; capital spending guidance for 2017; and expected rates of return;
  • with respect to the Company's Thermal Developments:  expectations regarding the addition of nameplate capacity over the next five years, including at Rush Lake 2, DEE Valley, Spruce Lake North and Spruce Lake Central; expected timing and volume of production ramp-up at Tucker; and expected timing to tie in 14 new well pairs at Sunrise;
  • with respect to the Company's Downstream operating segment:  plans to increase feedstock flexibility, optimize the product slate and increase margin capture; an expected increase to asphalt capacity at the Lloydminster Complex; and an expected increase to heavy oil processing capacity and timing for such increase at the Lima, Ohio refinery;
  • with respect to the Company's Asia Pacific region:  expectations regarding production growth and fixed-price gas contracts over the five-year plan; the expected timing of commencement of first sales gas and the expected timing of ramp-up to full gas rates at the BD Gas Project; expected timing of first production at the MDA-MBH and MDK fields; drilling plans for Block 16/25 and Block 15/33; and the anticipated timing for project sanction at Liuhua 29-1; and
  • with respect to the Company's Atlantic region:  the timing of first production and the timing and volume of gross peak production capacity at West White Rose; timing to bring an additional infill well on production at White Rose; and drilling plans in the Flemish Pass Basin.

Certain of the information in this presentation is “financial outlook” within the meaning of applicable securities laws.  The purpose of this financial outlook is to provide readers with disclosure regarding the Company’s reasonable expectations as to the anticipated results of its proposed business activities.  Readers are cautioned that this financial outlook may not be appropriate for other purposes.

Although the Company believes that the expectations reflected by the forward-looking statements presented in this presentation are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources including third party consultants, suppliers, regulators and other sources.

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Husky.

The Company’s Annual Information Form for the year ended December 31, 2016 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.

New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon management’s assessment of the future considering all information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.


This presentation contains certain terms which do not have any standardized meanings prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers.  None of these measures are used to enhance the Company's reported financial performance or position.  With the exception of funds from operations and free cash flow, there are no comparable measures to these non-GAAP measures in accordance with IFRS.  The following non-GAAP measures are considered to be useful as complementary measures in assessing Husky's financial performance, efficiency and liquidity:

  • "Funds from operations" is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, "cash flow – operating activities" as determined in accordance with IFRS, as an indicator of financial performance.  Funds from operations is presented in the Company’s financial reports to assist management and investors in analyzing operating performance by business in the stated period.  Funds from operations equals cash flow – operating activities plus items not affecting cash, which include settlement of asset retirement obligations, deferred revenue, income taxes received (paid), interest received and change in non-cash working capital.
  • "Free cash flow" is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, "cash flow – operating activities" as determined in accordance with IFRS, as an indicator of financial performance.  Free cash flow is presented in this presentation to assist management and investors in analyzing operating performance by business in the stated period.  Free cash flow equals net earnings (loss) plus items not affecting cash which include accretion, depletion, depreciation, amortization and impairment, inventory write-downs to net realizable value, exploration and evaluation expenses, deferred income taxes (recoveries), foreign exchange (gain) loss, stock-based compensation, loss (gain) on sale of property, plant, and equipment, unrealized mark to market loss (gain), and other non-cash items less capital expenditures.
  • "Net debt" is a non-GAAP measure that equals total debt less cash and cash equivalents.  Total debt is calculated as long-term debt, long-term debt due within one year and short-term debt.  Net debt is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength.
  • "Net debt to funds from operations" is a non-GAAP measure that equals net debt divided by funds from operations.  Net debt to funds from operations is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength.
  • "Operating netback" is a common non-GAAP metric used in the oil and gas industry.  This measure assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level.  Operating netback is calculated as realized price less royalties, operating costs and transportation costs on a per unit basis.
  • “Sustaining capital” is the additional development capital that is required by the business to maintain production and operations at existing levels.  Development capital includes the cost to drill, complete, equip and tie-in wells to existing infrastructure.  Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers.
  • "Earnings break-even" reflects the estimated WTI oil price per barrel priced in US dollars required in order to generate a net income of Cdn$0 in the 12-month period ending December 31, 2017.  This assumption is based on holding several variables constant throughout the period, including:  foreign exchange rate, light-heavy oil differentials, realized refining margins, forecast utilization of downstream facilities, estimated production levels and other factors consistent with normal oil and gas company operations.  Earnings break-even is used to assess the impact of changes in WTI oil prices on the net earnings of the Company and could impact future investment decisions.
  • "Cash break-even" reflects the estimated WTI oil price per barrel priced in US dollars required in order to generate operating cash flow equal to the Company’s sustaining capital requirements in Canadian dollars in the 12-month period ending December 31, 2017.  This assumption is based on holding several variables constant throughout the period, including:  foreign exchange rate, light-heavy oil differentials, realized refining margins, forecast utilization of downstream facilities, estimated production levels and other factors consistent with normal oil and gas company operations.  Cash break-even is used to assess the impact of changes in WTI oil prices on the net earnings of the Company and could impact future investment decisions.


Unless otherwise indicated:  (i) projected and historical production volumes provided represent the Company’s working interest share before royalties; and (ii) historical production volumes provided are for the year ended December 31, 2016.

The Company uses the term "barrels of oil equivalent" (or "boe"), which is consistent with other oil and gas companies’ disclosures, and is calculated on an energy equivalence basis applicable at the burner tip whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas.  The term boe is used to express the sum of the total company products in one unit that can be used for comparisons.  Readers are cautioned that the term boe may be misleading, particularly if used in isolation.  This measure is used for consistency with other oil and gas companies and does not represent value equivalency at the wellhead.

The Company uses the term "operating costs per barrel", which is consistent with other oil and gas producer’s disclosures, and is calculated by dividing total operating costs for the Company’s thermal bitumen or non-thermal production, as applicable, by the total barrels of such thermal or non-thermal production, as applicable.  The term is used to express operating costs on a per barrel basis that can be used for comparison purposes.

The Company uses the term "reserve replacement ratio", which is consistent with other oil and gas companies’ disclosures.  Reserve replacement ratios for a given period are determined by taking the Company's incremental proved reserves additions for that period divided by the Company's upstream gross production for the same period.  The reserve replacement ratio measures the amount of reserves added to a company's reserves base during a given period relative to the amount of oil and gas produced during that same period.  A company's reserve replacement ratio must be at least 100 percent for the company to maintain its reserves.  The reserve replacement ratio only measures the amount of reserves added to a company's reserves base during a given period.

All currency is expressed in Canadian dollars unless otherwise indicated.

CONTACT: For further information, please contact: Investor Inquiries: Rob Knowles Manager, Investor Relations Husky Energy Inc. 587-747-2116 Media Inquiries: Mel Duvall Manager, Media & Issues Husky Energy Inc. 403-513-7602
Categories: State

LINN Energy Announces Sale of Salt Creek for $71.5 Million and Extinguishes All Debt Pro-forma of Announced Transactions

Oil - 30 May 2017 - 5:45am

HOUSTON, May 30, 2017 (GLOBE NEWSWIRE) -- LINN Energy, Inc. (OTCQB:LNGG) (“LINN” or the “Company”) announced today that it has signed a definitive agreement to sell its interest in properties located in the Salt Creek Field in Wyoming to Denbury Resources Inc. for a contract price of $71.5 million, subject to closing adjustments.

This sale represents the second executed agreement of the Company’s non-core divestiture program. LINN continues to market the previously announced non-core asset sales and there remains significant interest in each of those packages. Year-to-date, the Company has announced sale agreements with contract prices totaling $916 million with net proceeds expected to be used to reduce outstanding borrowings under the Company’s revolving credit facility and term loan. Pro-forma for these transactions, the Company expects to extinguish all remaining outstanding debt.

The Wyoming properties consist of non-operated interest in approximately 5,000 net acres in the Salt Creek Field. First quarter net production was approximately 2,000 BOE/d, proved developed reserves of ~9 MMBOE(1) and proved developed PV-10 of approximately $54 million.(2) The Company forecasts full-year adjusted EBITDAX associated with these properties of approximately $5 million.(3) In the second half of the year, the Company had budgeted $4 million of capital for the development of these properties. This capital will be redeployed for the development of growth projects or added as additional cash on the balance sheet to be used to maximize shareholder returns.

“The Salt Creek sale marks a milestone in the ongoing transformation of LINN from a highly levered production-based MLP to a streamlined growth-oriented enterprise. Pro-forma following the closing of the Jonah, South Belridge and Salt Creek asset sales, the Company will have extinguished all remaining outstanding debt. This is a significant achievement for the company considering it had approximately $8.4 billion in debt outstanding at the end of 2015. Both management and the Board will continue to work hand-in-hand to execute on LINN’s transformative business plan, including the sale of the remaining non-core assets, accelerating investment in key horizontal growth plays, focusing on our overall cost structure to become a best-in-class low cost operator and using future cash proceeds to maximize shareholder returns,” said CEO Mark Ellis and Chairman Evan Lederman.

The transaction is expected to close in the second quarter of 2017 with an effective date of March 1, 2017. This transaction is subject to satisfactory completion of title and environmental due diligence, as well as the satisfaction of closing conditions.

CIBC Griffis & Small and Jefferies LLC acted as co-financial advisors and Kirkland & Ellis LLP as legal counsel during the transaction.

  1. Proved developed reserves as of March 1, 2017 with updated pricing of $3.00 per MMBtu for natural gas and $50.00 per bbl for oil.
  2. PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows. The Company’s calculation of PV-10 herein differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is calculated before income taxes with the pricing and timing assumptions noted in footnote (1)
  3. The non-GAAP financial measure of adjusted EBITDAX, as defined by the Company, may not be comparable to similarly titled measures used by other companies.  Therefore, this non-GAAP measure should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP.  Adjusted EBITDAX should not be considered in isolation or as a substitute for GAAP. As previously disclosed, total company (LINN Energy, Inc.) projected adjusted EBITDAX for 2017 is $496 million and total expected capital expenditures for 2017 is $413 million based on pricing estimates of $3.33 per MMBtu for natural gas and $50.51 per bbl for oil.


LINN Energy, Inc. was formed in February 2017 as the reorganized successor to LINN Energy, LLC. Headquartered in Houston, Texas, the Company’s core focus is the upstream and midstream development of the SCOOP / STACK / Merge in Oklahoma. Additionally, the Company is pursuing emerging horizontal opportunities in the Mid-Continent, Rockies, North Louisiana and East Texas while continuing to add value by efficiently operating and applying new technology to a diverse set of long-life producing assets. More information about LINN Energy is available at www.linnenergy.com.

Forward-Looking Statements
Statements made in this press release that are not historical facts are “forward-looking statements.” These statements are based on certain assumptions and expectations made by the Company which reflect management’s experience, estimates and perception of historical trends, current conditions, and anticipated future developments. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to financial performance and results, ability to improve our financial results and profitability following emergence from bankruptcy, ability to list our common stock on an established securities market, availability of sufficient cash flow to execute our business plan, ability to execute planned asset sales, continued low or further  declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to  hedge future production, ability to replace reserves and efficiently develop current reserves, the regulatory environment and other important factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Please read “Risk Factors” in the Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and other public filings. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information or future events.

CONTACT: CONTACTS: LINN Energy, Inc. Investors: Thomas Belsha, Vice President — Investor Relations & Corporate Development  (281) 840-4110 ir@linnenergy.com
Categories: State

Denbury Resources to Acquire Interest in Rockies CO2 Flood

Oil - 30 May 2017 - 5:30am

PLANO, Texas, May 30, 2017 (GLOBE NEWSWIRE) -- Denbury Resources Inc. (NYSE:DNR) (“Denbury” or the “Company”) today announced that it has entered into a definitive agreement with certain subsidiaries of Linn Energy, Inc. to acquire their 23% non-operated working interest in Salt Creek Field in Wyoming for $71.5 million.  Denbury plans to initially fund the acquisition with its bank line, but anticipates this cost would ultimately be offset through the sale of non-productive surface acreage ideally suited for commercial development in the Houston area, which Denbury is currently preparing to market.

Net production for the acquired interest is currently estimated at 2,100 barrels per day and is expected to increase over the next several years based on the planned field development.   Proved developed reserves for the acquired interest are estimated at approximately 9 million barrels of oil (“MMBbls”), and Denbury expects to recognize an additional 9 MMBbls of proved undeveloped reserves based on current development plans, resulting in estimated finding and development costs of less than $7 per barrel including both acquisition and future development costs.  Estimated capital costs for 2017 are approximately $5 million.

Chris Kendall, Denbury’s President and COO, commented, "Salt Creek is a great fit for Denbury, building scale in the heart of our core Rockies region, with production growing and many opportunities for future expansion in this large and long-lived field. The acquisition builds on our goal of resuming production growth by 2018, and its attractive price should improve our credit metrics in the near term, with the opportunity for additional enhancements in the future.”

The acquisition is expected to close in late June and is subject to satisfactory completion of due diligence reviews and customary closing conditions.  The purchase price is subject to standard purchase price adjustments for revenues and costs between the March 1, 2017 effective date and the closing date of the transaction.

Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  The Company’s goal is to increase the value of its properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.  For more information about Denbury, please visit www.denbury.com.

This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties including estimates of oil reserves, future volumes recoverable with a CO2 flood, and daily production volumes of the acquired assets, and other risks and uncertainties detailed in the Company’s filings with the Securities and Exchange Commission, including Denbury’s most recent reports on Form 10-K and Form 10-Q.  These risks and uncertainties are incorporated by this reference as though fully set forth herein.  These statements are based on engineering, geological, financial and operating assumptions that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met.  Actual results may vary materially.  In addition, any forward-looking statements represent the Company’s estimates only as of today and should not be relied upon as representing its estimates as of any future date.  Denbury assumes no obligation to update its forward-looking statements.

CONTACT: DENBURY CONTACTS: Mark C. Allen, Senior Vice President and Chief Financial Officer, 972.673.2000 John Mayer, Investor Relations, 972.673.2383
Categories: State

Petro River Strikes Second Oil Field Discovery in Osage County, Oklahoma in the Past 30 Days

Oil - 30 May 2017 - 5:00am

New York, NY, May 30, 2017 (GLOBE NEWSWIRE) -- Petro River Oil Corp. (OTCBB: PTRC) (“Petro River” or the “Company”), an independent oil and gas exploration company, announced today the discovery of a second oil field in its 106,500 acre concession in Osage County, OK following the successful drilling of the Red Fork 1-3 exploration well.

The Red Fork 1-3 well was spud May 15th, 2017 and was drilled to a depth of approximately 2,820 feet. Initial results indicate up to 30 feet of oil productive formation.  Following flow and fracking tests, the Company plans to confirm IP rates. 

The Red Fork 1-3 well tested multiple zones, which resulted in the discovery of  a separate chat field, potentially larger than the 20 feet of oil productive formation in the Chat 2-11 discovery announced on May 15, 2017.     

This discovery continues to validate the Company’s use of modern 3D seismic technology to identify oil structures that were overlooked in historically prolific areas. The 3D seismic identified structures containing potentially over 2.5 million barrels of oil on 1,610 acres of the 4,480 acres of structural closure. 

The Company plans to announce a development program following further results from both the Red Fork 1-3 and Chat 2-11.

“This is a significant 2nd discovery for Petro River and we are excited with the initial results,” said Petro River president Stephen Brunner.

In addition, the Company is currently using similar 3D seismic technology on its California projects, which have significantly larger prospective reserves.


Petro River Oil Corp. (OTC: PTRC) is an independent energy company with its core holdings in Northeast Oklahoma and Kern County, California. Petro River’s strategy is to apply modern technology, such as 3-D Seismic analysis to exploit hydrocarbon-prone resources in historically prolific plays and underexplored prospective basins to build reserves and to create value for the Company and its shareholders. Petro River owns a 20% equity interest in Horizon Energy Partners, LLC and its’ president, Stephen Brunner, is also a member of the Board of Managers of Horizon Energy Partners, LLC.


This news release contains forward-looking and other statements that are not historical facts. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward looking statements will not occur, which may cause actual performance and results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward looking statements. These forward looking statements, projections and statements are subject to change and could differ materially from final reported results. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the dates on which they are made. Petro River assumes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable securities law. Additionally, Petro River undertakes no obligation to comment on the expectations of, or statements made by, third parties in respect to the matters discussed above. Readers should also carefully review the “Risk Factors” in Petro River’s annual report on Form 10-K, its quarterly reports on Form 10-Q, and other reports filed with the SEC under the Securities Exchange Act of 1934, as amended.

For additional information about Petro River Oil, please visit http://petroriveroil.com/ or contact:

CONTACT: Investor Relations ir@petroriveroil.com telephone: (469) 828-3900
Categories: State
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