Paul Reichmann, real estate magnate, dies at 83

Once the head of the largest real estate development company in the world, which went bankrupt in 1992, Paul Reichmann died Friday in Toronto. He was 83.

The reclusive Reichmann brothers built Olympia & York into a major international development firm after starting out as a small company marketing flooring and tile in Toronto.

The five Reichmann brothers were the sons of Orthodox Hungarian Jews who fled central Europe during the Second World War.

Older brother Edward started Olympia Flooring and Tile in Montreal and was joined in Canada by Paul, Albert, Louis and Ralph. After the brothers began a small company in Toronto, Paul Reichmann was the force who parlayed it into a global real estate empire.  

Their developments included First Canadian Place in Toronto, the World Financial Center (right next to the World Trade Center in New York), and Canary Wharf in London.

Paul Reichmann was born in Vienna in 1930, where his father, Samuel, had his business at the time. His mother's name was Renée.

Paul Reichmann is shown in London in 1989. He was the driving force behind the huge Canary Wharf development in the British capital. (Canadian Press)

By sheer luck, in 1938, the family was visiting Paul's grandfather in Hungary when the Nazis occupied Austria and annexed it with Germany.

They settled in Paris for a time, but by 1940, the Nazis were there too. Late in life, Reichmann could still remember the Nazi bombing of refugees south of Paris.

The family moved to Tangier in Morocco, where they prospered, as his father became a successful currency trader.

When the war ended, Paul studied religion in Britain and Israel, and became a rabbi. In 1953, he went back to Morocco and became a shirt retailer. That same year he married Lea Feldman.

In 1956, Paul joined his brother Edward in Montreal. Then, joined by brothers Albert and Ralph, they started a development business in Toronto.

Initially, they built warehouses and commercial buildings. Their first major project was the development of Flemingdon Park in Toronto's Don Mills neighbourhood.

In 1971, they advanced right into the heart of Toronto's financial district and won the contract to build what was then Canada's tallest building, First Canadian Place, at King and Bay streets.

By the 1980s, Olympia & York was the largest property development firm in the world, having bought a portfolio of skyscrapers in New York.

"He seemed to have this extraordinary knack of being able to see value where other people couldn't see it, and also extracting value from the buildings he built by financing them in creative ways and raising money to go on to bigger and better things," said Peter Foster, the author of the 1993 book, Towers of Debt: The Rise and Fall of the Reichmanns.

In 1980, they got 50-per-cent control of Brinco Ltd., a natural resources development company in Newfoundland and Labrador. The next year they bought an 82-per-cent controlling interest in Abitibi-Price Inc., and they held a significant share of Royal Trust Company. In 1985, they bought Gulf Canada Resources Ltd.

Along the way, they had acquired English Property Corp., one of the largest developers in Britain. That was the company that enabled them to build Canary Wharf in east London, at once their greatest achievement and their greatest failure.

The largest real estate development in the world at the time, it boasted Britain's tallest building, One Canada Square.

It was Reichmann's vision (only now coming to fruition) that it would be a kind of Wall Street of London and successfully compete with the city's historic financial district known as the City.

But by the time it was finished in 1992, the London commercial property market had collapsed, bringing down Olympia & York.  In March of that year, Reichmann was forced to resign as president.

When it filed for bankruptcy in May 1992, Olympia & York owed more than $20 billion US to various banks and investors. It was closed down in 1993, and the Reichmanns were left with a small firm, Olympia & York Properties Corp.

There are several theories about what went wrong with Paul Reichmann's judgment when he embarked on the Canary Wharf enterprise.

His reliance on his own business instincts may have led him astray, claims Foster.

According to the president of Canary Wharf, George Iacobescu, the Iron Lady herself, Margaret Thatcher, had personally called to ask Olympia & York to take on the development, and she promised that the Jubilee Line of the London Underground would be extended to speed up the trip to Canary Wharf from central London.

That promise was key to the development's success. But the line was not extended in her time. It opened only in 2000, long after the demise of Olympia & York.

Paul Reichmann was famous for sealing deals with a handshake and not bothering with corporate lawyers, and he always kept his word. He may have thought Thatcher would do the same thing.

The Olympia & York bankruptcy did not leave Reichmann poor by any means. In 2011 he was still listed among the richest Canadians. At number 30 on the list, his net worth was given as $1.83 billion, and that was up slightly from the year before.

In his usual secretive manner, Paul had continued with canny investments. For instance, he owned 70 per cent of Central Park Lodges, which in 1999 operated 74 retirement homes, 63 in Canada, the rest in the U.S., according to the National Post.

He was also involved in a $107-million project in Israel, according to the Jerusalem Post newspaper.

His company, IPC Jerusalem Ltd., built a five-star hotel and luxury condominium, called The Palace Jerusalem — The Waldorf Astoria Collection.

In 2004, he again bought a controlling stake in Canary Wharf, a development that by then was considered essential to the fabric of London. He gave it up in 2009.

Reichmann always lived humbly and austerely, in keeping with his ultra-Orthodox Jewish beliefs, even to the point of closing down his many development projects, and allowing no work there on the Sabbath.

"His accomplishments were titanic, just look at the Bank of Montreal building for example," said Tom Caldwell of Caldwell Securities. "Yes, he got bushwacked in Canary Wharf in England, but he came from a small business to play in the big leagues and he played it well. And he played it with dignity."

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New Zealand Energy Announces Second Quarter Results and Operational Update

VANCOUVER, BRITISH COLUMBIA--(Marketwired - Aug. 29, 2013) - New Zealand Energy Corp. ("NZEC" or the "Company") (TSX VENTURE:NZ)(OTCQX:NZERF) has released the results of its second quarter ended June 30, 2013. Details of the Company's financial results are described in the Unaudited Consolidated Financial Statements and Management's Discussion and Analysis which, together with further details on each of the Company's projects, will be available on the Company's website at www.newzealandenergy.com and on SEDAR at www.sedar.com. All amounts are in Canadian dollars unless otherwise stated.

HIGHLIGHTS

Production and Development

Announced development plans for the Taranaki Basin until the end of 2014, forecasting exit production rates of 2,300 BOE/day (applying mid-case assumptions)1 48,752 barrels of oil ("bbl") produced and 49,204 bbl sold during six-month period, generating pre-tax oil sales of $5.3 million Positive net cash flow from petroleum operations during six-month period of approximately $1.7 million Average field netback during six-month period of $35.10/bbl Substantial reduction to direct production costs at Copper Moki site during June 2013 as a result of the installation of permanent production facilities 56,717 bbl produced and 59,623 bbl sold year to date (August 26, 2013), generating pre-tax oil sales of approximately $6.4 million Cumulative production of 264,938 bbl since commencement of production, generating pre-tax oil sales (including sales from pre-production testing) of approximately $28.5 million Initiated installation of artificial lift at Waitapu-2 well Received results of RPS reservoir study, providing the Company with a better understanding of Mt. Messenger reservoir characteristics and declines Lodged an application for a petroleum mining permit that will encompass the Company's Copper Moki, Waitapu, Arakamu and Wairere sites in the Eltham Permit (18.73 km2)

Acquisition of TWN Licences and TWN Assets from Origin Energy

Amended deal terms related to the acquisition, resulting in a simplified sale and reduced purchase price Entered into a binding letter agreement with L&M Energy ("L&M") to explore and operate the TWN Licences and TWN Assets, securing $18.25 million from L&M to purchase a 50% interest in the assets Obtained an extension to secure remaining required funds ($9.25 million) until September 30, 2013 Settled the HSBC operating line of credit Announced 2P reserves of 1.07 million BOE attributed to the TWN Licences (NZEC's interest)2 1 Barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. The boe conversion ratio of 6 Mcf : 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. See Forward-looking Information for assumptions associated with production forecast.2 Reserves associated with the TWN Licences, as previously announced in an NZEC press release on June 17, 2013, will not be attributable to NZEC until the Company has completed the acquisition of assets from Origin and filed an updated Reserve report under NI 51-101. NZEC's shares of the TWN Reserves is 50%, as per the terms of the TWN Arrangement with L&M.

FINANCIAL SNAPSHOT

Six months
ended
June 30, 2013Three months
ended
June 30, 2013Six months
ended
June 30, 2012Three months
ended
June 30, 2012Total comprehensive income (loss)(Loss) earnings per share - basic and diluted

Note: The abbreviation bbl means barrel or barrels of oil.

Six-month Operating Results

During the six-month period ended June 30, 2013, the Company produced 48,752 barrels of oil and sold 49,204 barrels for total oil sales of $5,277,878, with an average oil sale price of $107.27 per barrel. Total recorded production revenue, net of a 5% royalty payable to the New Zealand Government (an average of $4.94 per barrel), was $5,034,958. Production costs during the six-month period ended June 30, 2013 totalled $3,307,876, or an average of $67.23 per barrel, generating an average field netback of $35.10 per barrel during the period. NZEC calculates the netback as the oil sale price less fixed and variable production costs and a 5% royalty. The notable reduction in netback during the six-month period ended June 30, 2013, is predominantly the result of decreased oil production. As previously announced, the Company had shut in the Waitapu-2 well during May 2013 in order to gather critical data for the Mt. Messenger reservoir study (see Reservoir Study) and to evaluate and install artificial lift.

The Company undertook a number of reservoir and production tests with the objective of optimizing oil production, and these tests have added to production costs. During the six-month period ended June 30, 2013, fixed production costs represented approximately 84% of total production costs. Installation of the Copper Moki surface facilities was completed in May and, as expected, this resulted in a reduction in production costs for the Copper Moki site during the month of June 2013, as discussed under June Operating Results - Copper Moki Site Only. Although shutting in the Waitapu-2 well in May 2013 reduced some of the fixed operating costs, the Company continues to incur costs on that site.

Three-month Operating Results

During the three-month period ended June 30, 2013, the Company produced 18,573 barrels of oil and sold 21,958 barrels for total oil sales of $2,216,815, with an average oil sale price of $100.96 per barrel. Total recorded production revenue, net of a 5% royalty payable to the New Zealand Government (an average of $4.88 per barrel), was $2,109,700. Production costs during the three-month period ended June 30, 2013 totalled $1,616,471, or an average of $73.62 per barrel, generating an average field netback of $22.46 per barrel during the period.

As demonstrated in Six-month Operating Results, reduced production following the shut-in of Waitapu-2 greatly impacted the three-month netback results, although this was partially offset by reduced production costs related to the Copper Moki site following the commissioning of surface facilities (see June Operating Results - Copper Moki Site Only).

June Operating Results - Copper Moki Site Only

The Company is starting to see the positive effect on production costs of installation of surface facilities as reflected in reduced production costs related to the Copper Moki site during June 2013. Following the commissioning of surface facilities on the Copper Moki site in May 2013, the Company incurred direct production costs of approximately $165,000 to produce 4,740 barrels of oil, which amounted to $34.81 per barrel during the month of June 2013, a significantly lower production cost per barrel than the quarterly average of $73.62 per barrel. This is also comparable to management's estimate of well-site production costs of NZ$40 per barrel as assumed in management's forecast of cash flows from operations referenced in the Company's August 6, 2013 press release.

Considering the proportion of fixed production costs reported for the quarter ended June 30, 2013, as well as netbacks reported in prior periods, the direct production costs per barrel is reflective of the economies of scale. Thus, further savings should arise from higher production levels from future developments.

At August 26, 2013, the Company had an estimated $4.6 million in net working capital.

ACQUISITION OF INTEREST IN UPSTREAM AND MIDSTREAM ASSETS

As previously announced, the Company has entered into an agreement with Origin Energy Resources NZ (TAWN) Limited ("Origin") to acquire three (net) petroleum mining licences in the Taranaki Basin totalling 23,049 acres (93.3 km2) - the Tariki, Waihapa and Ngaere Licences (the "TWN Licences") - as well as the Waihapa Production Station and associated gathering and sales infrastructure (the "TWN Assets"). On August 12, the Company announced that Origin had agreed to extend the deadline for satisfying the financing condition precedent for the acquisition from August 14, 2013 to September 30, 2013, and to extend the deadline for obtaining the required government approvals from September 13, 2013 to October 14, 2013. In exchange, the Company agreed to increase its acquisition deposit to $6 million.

L&M Letter Agreement to Form Joint Arrangement

On July 30, 2013, the Company announced that it had entered into a binding agreement (the "L&M Letter Agreement") with L&M Energy ("L&M") to form a 50/50 joint arrangement to explore, develop and operate the TWN Licences and the TWN Assets. Once the joint arrangement is completed, the Company and L&M will each own 50% of the TWN Licences and will also hold a 50% interest in the TWN Assets (the "TWN Joint Arrangement"). The reserves and resources estimated for the TWN Licences, as announced on June 17, 2013, will be attributable to NZEC on a 50% basis upon closing of the acquisition and the TWN Joint Arrangement, and filing of an updated reserve report.

Under the terms of the L&M Letter Agreement, L&M will contribute $18.25 million towards the approximately $33.5 million purchase consideration agreed to under the Origin Sale and Purchase Agreement, in order to obtain a 50% interest in the TWN Joint Arrangement. L&M will also contribute 50% of all future development and operating expenditures.

The Company will become the operator of the TWN Joint Arrangement, and decisions regarding exploration, development and operations of the TWN Joint Arrangement will be made by management committees with equal representation from both the Company and L&M.

The Company will be responsible for funding the $15.25 million balance of the $33.5 million purchase consideration agreed to under the Origin Sale and Purchase Agreement. The Company has paid a $6 million acquisition deposit to Origin, leaving $9.25 million to be funded to complete the acquisition.

The concurrent completion of the acquisition and the L&M Letter Agreement is subject to the Company placing the remainder of the purchase price into an escrow account by September 30, 2013, Origin and Contact consenting to L&M becoming a party to the definitive agreements, as well as receiving the relevant government approvals.

PROPERTY REVIEW

Taranaki Basin

The Taranaki Basin is situated on the west coast of the North Island and is currently New Zealand's only oil and gas producing basin, with total production of approximately 130,000 barrels of oil equivalent per day ("boe/d") from 18 fields. Within the Taranaki Basin, NZEC holds a 100% interest in the Eltham Permit, a 65% interest in the Alton Permit in joint arrangement with L&M, and a 60% interest in the Manaia Permit in joint arrangement with New Zealand Oil & Gas ("NZOG"). The Eltham Permit covers approximately 93,166 acres (377 km2) of which approximately 31,877 acres (129 km2) are offshore in shallow water. The Alton Permit covers approximately 119,204 onshore acres (482 km2). The Manaia Permit covers approximately 27,426 onshore acres (111 km2) and was granted to NZEC and NZOG in December 2012 as part of the annual New Zealand block offer for exploration permits.

NZEC also expects to acquire 50% of the three TWN Licences and to hold a 50% interest in the TWN Assets upon completion of the acquisition of assets from Origin, as outlined in Acquisition of Interest in Upstream and Midstream Assets.

Production

At the date of this MD&A, three of the Company's four commercially producing wells are in active production. The Waitapu-2 well is currently shut in and installation of artificial lift and surface facilities is underway. During the quarter, the Company also temporarily shut-in its Copper Moki-3 well to replace the down-hole pump, which seized as a result of fines settling in the pump during commissioning of the Copper Moki surface facilities. The wells are producing light oil that is trucked to the Shell-operated Omata Tank Farm and sold at Brent pricing. Cumulatively, as of the date of this report, the Company has produced approximately 264,938 barrels of oil, with cumulative pre-tax oil sales of approximately $28.5 million, including sales from oil produced during testing (net results of operations are discussed under Results of Operations). The wells have consistently produced between 123 bbl/d and 162 bbl/d since July 1, 2013, with an average production rate of 144 bbl/d, indicating that oil production from the Copper Moki wells appears to have stabilized. Over 26 production days in August 2013, the wells have collectively produced oil at an average rate of 139 bbl/d and extracted gas at an average rate of 490 mcf/d. The Company is not yet generating cash flows from extracted gas.

Copper Moki-1 has been producing since December 10, 2011, Copper Moki-2 since April 1, 2012 and Copper Moki-3 since July 2, 2012. All three wells produce ~41° API oil from the Mt. Messenger formation and flowed from natural reservoir pressure until October 2012, when NZEC installed artificial lift (pump jacks) to stabilize production rates.

Waitapu-2 commenced production on December 20, 2012 and was shut-in in May 2013 as described above. The well produces ~40° API oil from the Mt. Messenger formation and flowed from natural reservoir pressure until shut-in. Installation of artificial lift is currently underway. In addition to installation of artificial lift, during the period the Company ran down-hole gauges into Waitapu-2 that measures the bottom hole temperature and pressure of the reservoir. These data were critical to the recently completed Mt. Messenger reservoir study (see below).

Reservoir Study

Production declines from the Copper Moki wells have been greater than expected and this prompted the Company to initiate an independent reservoir study through RPS Group PLC, a world leader in well evaluation. The study provided the Company with a better understanding of reservoir characteristics and declines, based on data from Waitapu-2, the three Copper Moki wells, and other Mt. Messenger wells in the region.

The RPS study concluded that declines are not related to wax buildup or mechanical issues. Information from the study and from a proprietary database merging five 3D seismic surveys has allowed the Company to refine its Mt. Messenger exploitation strategy, which includes:

Choosing optimally sized targets based on interpretation of the merged 3D dataset, Reducing costs by drilling multiple wells from each pad, and Prioritization of targets close to the Waihapa Production Station to expedite tie-in.

The Mt. Messenger formation remains an integral part of the Company's development plans, as described in the Outlook section. These development plans include the Horoi-1 well, which is expected to be drilled later this year on the Alton Permit.

Application for Eltham Petroleum Mining Permit

During the quarter ended June 30, 2013, the Company lodged an application for a petroleum mining permit that will have an initial duration of 15 years. This petroleum mining permit will cover 18.73 km2 within the area currently included under the Company's Eltham Permit and includes all sites on which the Company had previously drilled its ten exploration wells (i.e. the Copper Moki site, Waitapu site, Arakamu site, and the Wairere site). A successful application for the petroleum mining permit will extend the duration that the Company is able to operate within the area covered by the permit, and will also reduce the surface area within the existing Eltham Permit that will be subject to relinquishment in September 2013 when the Eltham Permit is due for extension.

East Coast Basin

The East Coast Basin of New Zealand's North Island hosts two prospective oil shale formations, the Waipawa and Whangai, which are the source of more than 300 oil and gas seeps. Within the East Coast Basin, NZEC holds a 100% interest in the Castlepoint Permit, which covers approximately 551,042 onshore acres (2,230 km2), and a 100% interest in the Ranui Permit, which covers approximately 223,087 onshore acres (903 km2) and is adjacent to the Castlepoint Permit. NZEC is considering relinquishing the Ranui Permit but has not yet made a definitive decision in this regard. On September 3, 2010, NZEC applied to the Minister of Energy to obtain a 100% interest in the East Cape Permit. The application is uncontested and the Company expects the East Cape Permit to be granted to NZEC upon completion of New Zealand Petroleum & Minerals' ("NZPAM") review of the application. The East Cape Permit covers approximately 1,067,495 onshore acres (4,320 km2) on the northeast tip of the North Island. In addition, NZEC has entered into a binding agreement with Westech to acquire 80% ownership and become operator of the Wairoa Permit, which covers approximately 267,862 onshore acres (1,084 km2) south of the East Cape Permit. Preliminary approval of transfer of ownership was obtained from NZPAM on December 20, 2012 and formation of a joint arrangement with Westech is subject to final NZPAM approval.

The Company has completed the coring of two test holes on the Castlepoint Permit. The Orui (125 metres total depth) and Te Mai (195 metres total depth) collected core data across the Waipawa and Whangai shales. NZEC also completed a test hole on the Ranui Permit. Ranui-2 was drilled to 1,440 metres, coring the Whangai shale across several intervals. In Q2-2012, NZEC completed 70 line km of 2D seismic data across the Castlepoint and Ranui permits to further its technical understanding of the area and identify targets for exploration in 2013.

The Wairoa Permit has been actively explored for many years, with extensive 2D seismic data across the permit and log data from more than 15 wells drilled on the property. Historical exploration focused on the conventional Miocene sands. NZEC's technical team has identified conventional opportunities as well as potential in the unconventional oil shales that underlie the property. NZEC's team knows the property well and provided extensive consulting services (through the consulting company Ian R Brown Associates) to previous permit holders, assisting with seismic acquisition and interpretation, well-site geology and regional prospectivity evaluation. In addition, NZEC's team assisted with permitting and land access agreements and worked extensively with local district council, local service providers, land owners and iwi groups, allowing the team to establish an excellent relationship with local communities. During Q1-2013 the Company completed a 50 km 2D seismic program on the property, the results of which are currently being processed and reviewed and will help to identify exploration targets on the permit.

OUTLOOK

On August 6, 2013, the Company announced its updated plans to develop its oil and gas assets in the Taranaki Basin, including its plans for exploration and development of the TWN Licences and integration of the TWN Assets. Completing the acquisition of the TWN Licences and TWN Assets will be transformative for NZEC, resulting in a fully integrated upstream/midstream company with the cash flow, infrastructure and inventory to support long-term growth.

Taranaki Basin

Owning 50% of the TWN Assets and TWN Licences will allow NZEC to optimize development of its existing permits. The gas supply that NZEC has identified to reactivate gas lift and production from existing Tikorangi wells on the TWN Licences will provide the blending gas required to deliver NZEC's Copper Moki gas to market, bringing additional cash flow to NZEC from the Copper Moki wells. The Company also plans to build a pipeline to connect the Waitapu-2 well to the Copper Moki site and is currently evaluating the economics of this initiative. The pipeline would effectively tie in the Waitapu gas production (and associated liquefied petroleum gas or "LPG") into the Waihapa Production Station via the Copper Moki pipeline.

As NZEC continues to explore the Eltham and Alton permits, the Company will focus on drill targets that are close to the Waihapa Production Station and associated pipelines, allowing for rapid and cost effective tie-in of both oil and gas production.

NZEC has prepared a detailed financial and production model outlining the exploration and development program for its Taranaki assets that has allowed the Company to forecast the impact of those activities on its production and cash flow. NZEC's activities planned to the end of 2014 in the Taranaki Basin are outlined in the table below:

PLANNED POST ACQUISITION WORK PROGRAMProduction Impact
(Exit 2014)Tikorangi well reactivations
-- Reactivate six existing Tikorangi wells with gas lift
-- High volume lift installation on two initial wellsIncluded in 2014
production belowMt. Messenger development
-- Waitapu artificial lift and tie-inTwo Mt. Messenger uphole completions in existing wells
-- Horoi exploration well (including surface infrastructure)Included in 2014
production belowTikorangi Well Reactivations
-- Increase water handling capacity at Waihapa Production Station
-- High volume lift installation on four remaining wellsNew Tikorangi wells
-- Drill two new Tikorangi wellsMt. Messenger development
-- Three new Mt. Messenger wells (including surface infrastructure)Kapuni development (cost to be funded by new JV partner)
-- Two new Kapuni wellsSeismic acquisition, G&G studies and OtherExit 2,300 boe/day
(including production from
existing wells)

The forecast on which the above information is based reflects management's mid-case production assumptions, while capital costs indicate management's net share of the capital cost to be incurred by the TWN Joint Arrangement.

Development and operating costs in the first 12 months following the date of this report are to be funded initially by existing working capital and cash flows from production. However, in order to carry out all of the planned development activities, the Company is considering a number of options to increase its financial capacity. These options include increasing cash flow from oil production, additional joint arrangements, commercial arrangements or other financing alternatives. For the assumptions related to the production forecast, refer to the full Management's Discussion & Analysis filed on the Company's website and on SEDAR.

East Coast Basin

NZEC has drilled two stratigraphic holes on its 100% working interest Castlepoint Permit and one stratigraphic hole on its 100% working interest Ranui Permit. These three stratigraphic test wells have advanced NZEC's understanding of the Waipawa and Whangai formations. A review of the geochemical and physical properties of the two shale packages, coupled with information from seismic data, has focused NZEC's exploration strategy for the area. The Company is actively seeking a joint venture partner for its East Coast permits. The Company is currently considering its plans for the Ranui Permit, including possible relinquishment of the permit.

NZEC has applied to NZPAM to extend the deadline for drilling the exploration well on the Castlepoint Permit to Q2-2014, while the Company continues to work towards obtaining the requisite consents and land access agreements for the Castlepoint Permit drill locations. The Company has met regularly with local communities to discuss its exploration plans.

NZEC completed a 50-km 2D seismic survey on the Wairoa Permit in Q2-2013 and is currently processing the data. The Company will finalize its exploration plans for the permit after reviewing all of the seismic and well log data.

The Company's application for the East Cape Permit is uncontested and NZEC expects the permit to be granted upon completion of NZPAM's review of the application.

SUMMARY OF QUARTERLY RESULTS

Exploration and evaluation assetsTotal comprehensive income (loss)Basic (loss) earnings per shareDiluted (loss) earnings per shareExploration and evaluation assetsTotal comprehensive income (loss)Basic (loss) earnings per shareDiluted (loss) earnings per share

On behalf of the Board of Directors

John Proust, Chief Executive Officer & Director

About New Zealand Energy Corp.

NZEC is an oil and natural gas company engaged in the production, development and exploration of petroleum and natural gas assets in New Zealand. NZEC's property portfolio collectively covers approximately 2.25 million acres (including permits and acquisitions pending) of conventional and unconventional prospects in the Taranaki Basin and East Coast Basin of New Zealand's North Island. The Company's management team has extensive experience exploring and developing oil and natural gas fields in New Zealand and Canada. NZEC plans to add shareholder value by executing a technically disciplined exploration and development program focused on the onshore and offshore oil and natural gas resources in the politically and fiscally stable country of New Zealand. NZEC is listed on the TSX Venture Exchange under the symbol "NZ" and on the OTCQX International under the symbol "NZERF". More information is available at www.newzealandenergy.com or by emailing info@newzealandenergy.com.

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

FORWARD-LOOKING INFORMATION

This document contains certain forward-looking information and forward-looking statements within the meaning of applicable securities legislation (collectively "forward-looking statements"). The use of any of the words "will", "intend", "objective", "become", "transforming", "potential", "continuing", "pursue", "subject to", "look forward", "unlocking" and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Such forward-looking statements should not be unduly relied upon. The Company believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct. This document contains forward-looking statements and assumptions pertaining to the following: business strategy, strength and focus; the granting of regulatory approvals; the timing for receipt of regulatory approvals; geological and engineering estimates relating to the resource potential of the properties; the estimated quantity and quality of the Company's oil and natural gas resources; supply and demand for oil and natural gas and the Company's ability to market crude oil and natural gas; expectations regarding the Company's ability to continually add to reserves and resources through acquisitions and development; the Company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the Company's ability to raise capital on appropriate terms, or at all; the ability of the Company to obtain the necessary approvals and secure the necessary financing to conclude the acquisition of assets from Origin on schedule, or at all; the ability of the Company to obtain the necessary approvals to conclude the TWN Joint Arrangement on schedule, or at all; the ability of the Company's subsidiaries to obtain mining permits and access rights in respect of land and resource and environmental consents; the recoverability of the Company's crude oil, natural gas reserves and resources; and future capital expenditures to be made by the Company.

Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in the document, such as the speculative nature of exploration, appraisal and development of oil and natural gas properties; uncertainties associated with estimating oil and natural gas resources; changes in the cost of operations, including costs of extracting and delivering oil and natural gas to market, that affect potential profitability of oil and natural gas exploration; operating hazards and risks inherent in oil and natural gas operations; volatility in market prices for oil and natural gas; market conditions that prevent the Company from raising the funds necessary for exploration and development on acceptable terms or at all; global financial market events that cause significant volatility in commodity prices; unexpected costs or liabilities for environmental matters; competition for, among other things, capital, acquisitions of resources, skilled personnel, and access to equipment and services required for exploration, development and production; changes in exchange rates, laws of New Zealand or laws of Canada affecting foreign trade, taxation and investment; failure to realize the anticipated benefits of acquisitions; and other factors. Readers are cautioned that the foregoing list of factors is not exhaustive. Statements relating to "reserves and resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources described can be profitably produced in the future. This document includes references to management's forecasts of future development, production and cash flows from such operations. The major assumptions applied by management are outlined in the MD&A, published on the Company's website and on SEDAR. The forward-looking statements contained in the document are expressly qualified by this cautionary statement. These statements speak only as of the date of this document and the Company does not undertake to update any forward-looking statements that are contained in this document, except in accordance with applicable securities laws.

CAUTIONARY NOTE REGARDING RESERVE ESTIMATES

The oil and gas reserves calculations and income projections were estimated in accordance with the Canadian Oil and Gas Evaluation Handbook ("COGEH") and National Instrument 51-101 ("NI 51-101"). The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf: one bbl was used by NZEC. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates. Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Revenue projections presented are based in part on forecasts of market prices, current exchange rates, inflation, market demand and government policy which are subject to uncertainties and may in future differ materially from the forecasts above. Present values of future net revenues do not necessarily represent the fair market value of the reserves evaluated. The report also contains forward-looking statements including expectations of future production and capital expenditures. Information concerning reserves may also be deemed to be forward looking as estimates imply that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated.

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Appulse Corporation: Announcing an Exclusive Canadian Services Provider Agreement With Flottweg Separation Technology Inc.

CALGARY, ALBERTA--(Marketwired - Aug. 29, 2013) - Appulse Corporation (TSX VENTURE:APL) ("Appulse") today announced that its primary operating subsidiary, Centrifuges Unlimited Inc. ("CUI ") has signed an exclusive authorized services provider agreement for Canada with Flottweg Separation Technology Inc., a subsidiary of Flottweg SE ("Flottweg"), headquartered in Vilsbiburg, Germany.

Flottweg is a major centrifuge manufacturer with a strong international reputation for quality. With an annual revenue for the group exceeding 140 million euros, Flottweg exports sophisticated separation equipment to all major markets, with eight prime business centers including Flottweg Separation Technology Inc. of Independence Kentucky, covering the United States and Canada. The company is increasing its focus on the Canadian market with applications in a variety of industries currently concentrated in central and eastern Canada.

Under terms of the agreement, CUI will provide maintenance, repair and start-up services to current and future Flottweg customers in Canada. All spare parts requirements will be facilitated through CUI from a local stock of Flottweg parts. CUI will also be involved in the sale of new Flottweg machines for the industrial market. In addition, the companies have entered into preliminary discussions related to the joint development of a new decanter style centrifuge related primarily to the oil industry including drilling mud applications.

About Appulse

Through its subsidiaries, Centrifuges Unlimited Inc., Rolyn Oilfield Services Inc., and Design Machining Unlimited Inc., Appulse specializes in the sales, servicing and refurbishing of centrifuge equipment, serving both domestic and international markets, and offers full service industrial machining. The Corporation continues to pursue expansion to its product base and geographic markets, in addition to adopting a program of controlled acquisitions complementing its current activities.

Further information on Appulse and its subsidiaries can be obtained through the Corporation's website, at www.appulsecorp.net and on SEDAR at www.sedar.com. Certain statements in this release are forward looking and the reader is cautioned that such information, although considered reasonable by the Corporation at the time of preparation, may prove to be incorrect.

Neither the 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.

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Estrella International Energy Services Ltd. Announces Filing of Q2 Financial Statements

TORONTO, ONTARIO--(Marketwired - Aug. 30, 2013) -

NOT FOR DISSEMINATION IN THE UNITED STATES OR THROUGH U.S. NEWSWIRES

Estrella International Energy Services Ltd. ("Estrella" or the "Company") (TSX VENTURE:EEN) announces that it has filed its Interim Condensed Consolidated Financial Statements and the related Management's Discussion and Analysis ("MD&A") for the three and six month period ended June 30, 2013. Copies of these documents can be found on the SEDAR website at www.sedar.com. In this press release all dollar amounts are in US$ '000 unless otherwise specified.

Financial Highlights for the Quarter Ended June 30, 2013

During the quarter the Company recorded the highest quarterly revenues to date of $18,717 ($16,868 in 2012), this notwithstanding that the Company's rig utilization rate was 57% (49% in 2012). The company achieved an exit utilization in June of 63%, resulting in the highest monthly revenues in the company's history of $6,862. Utilization outside of Colombia continues to be very strong, with further improvements in Colombia being the main area of focus for the company going forward.

The revenues for were offset by general and administrative expenses (exclusive of turnover tax) of $2,528 or 13.5% of revenues ($2,487 in 2012 or 14.7% of revenues), depreciation of $3,142 ($2,859 in 2012), interest expense of $1,932 ($2,338 in 2012) and oilfield expenses of $15,870 ($13,903 in 2012). For the quarter ended June 30, 2012, the Company also recorded other income of $523 ($1,186 during 2012). The net loss was $4,320 ($3,802 in 2012). The Company recorded an EBITDA of -$45 ($204 in 2012).

Significant Events Subsequent to the Quarter End

Subsequent to the quarter end, the Company completed its previously announced acquisition of San Antonio Internacional Co. Inc. ("SAIC") for a purchase price of approximately US$122 million (the "Acquisition"). Full details of the Acquisition and the associated transactions can be found in the Company's press releases dated June 17, 2013 and August 2, 2013.

On August 19, 2013, the Company held its annual general and special meeting of shareholders (the "AGM"). At the AGM the following persons were elected as directors for the Company for the ensuing year: Horacio Reyser, Warren Levy, Riccardo Rodriguez, Daniel Kokogian, Diego Acevedo, Remo Mancini and Phil MacDonnell. Collins Barrow LLP was appointed as auditor of the Company for the ensuing year. The stock option plan for the Company was also approved by the shareholders for the ensuing year.

At the AGM the disinterested shareholders of the Company overwhelmingly approved the proposed private placement of Series B Preference Shares to Ringo Holding L.P. as disclosed in the press release of the Company dated June 17, 2013. The private placement is expected to close in September, 2013.

The shareholders also overwhelmingly approved, as a special resolution, the proposed consolidation of the issued and outstanding common shares of the Company by a ratio of 100:1 or such lesser consolidation ratio as may be approved by the Board of Directors of the Company of at least 10:1. The directors of the Company have not yet fixed the consolidation ratio. It is expected that the consolidation will become effective on the closing date of the private placement referred to above.

About Estrella

Estrella is an oil and natural gas, geothermal and mining service company with operations throughout Latin and South America. It provides conventional drilling services; directional drilling services; tools and equipment sales and rentals; work-over and finishing services; and consulting and engineering services. The Corporation is headquartered in Buenos Aires, Argentina and has operating locations in five countries Latin and South America.

Forward Looking Statements

This press release may contain forward-looking statements which reflect management's expectations regarding future growth, results of operations, performance and business prospects of Estrella. These forward-looking statements may relate to, among other things, forecasts or expectations regarding business outlook for Estrella; commodity prices for oil and natural gas; oil and natural gas demand and production growth; debt service requirements for Estrella; improvements in operating procedures and technology; capital expenditures by Estrella and the oil and gas industry; the business strategies of Estella's customers; future global economic conditions; and future results of operations; expectations regarding the Corporation's ability to raise capital; realization of the anticipated benefits of acquisitions and dispositions, revenue growth, future acquisitions, generation of cash flow, and may also include other statements that are predictive in nature, or that depend upon or refer to future events or conditions, and can generally be identified by words such as "may", "will", "expects", "anticipates", "intends", "plans", "believes", "estimates", "guidance" or similar expressions. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. These statements are not historical facts or guarantees of future performance, but instead represent management's current expectations, estimates and projections regarding future events.

The reader is cautioned that assumptions used in the preparation of any forward-looking information may prove to be incorrect. Events or circumstances, such as future availability of capital on favourable terms, may cause actual results to differ materially from those predicted, as a result of numerous known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Estrella. The reader is cautioned not to place undue reliance on any forward-looking information. Such information, although considered reasonable by management at the time of preparation, may prove to be incorrect and actual results may differ materially from those anticipated. Forward-looking statements contained in this press release are expressly qualified by this cautionary statement. The forward-looking statements contained in this press release are made as of the date of this press release, and Estrella does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by securities law.

THIS PRESS RELEASE, REQUIRED BY APPLICABLE CANADIAN LAWS, IS NOT FOR DISTRIBUTION TO U.S. NEWS SERVICES OR FOR DISSEMINATION IN THE UNITED STATES, AND DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO SELL ANY OF THE SECURITIES DESCRIBED HEREIN IN THE UNITED STATES. THESE SECURITIES HAVE NOT BEEN, AND WILL NOT BE, REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED, OR ANY STATE SECURITIES LAWS, AND MAY NOT BE OFFERED OR SOLD IN THE UNITED STATES OR TO U.S. PERSONS UNLESS REGISTERED OR EXEMPT THEREFROM.

Neither the 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.

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Golar LNG Limited Dividend Information

HAMILTON, BERMUDA--(Marketwired - Aug 29, 2013) - Reference is made to the second quarter 2013 report released on August 29, 2013. Golar LNG will be trading ex-dividend of a total dividend of $0.45 per share on September 11, 2013. The record date is September 13, 2013, and the dividend will be paid on or about September 26, 2013.

Golar LNG Limited

Hamilton, Bermuda

August 29, 2013

This announcement is distributed by Thomson Reuters on behalf of Thomson Reuters clients. The owner of this announcement warrants that:

(i) the releases contained herein are protected by copyright and other applicable laws; and

(ii) they are solely responsible for the content, accuracy and originality of the information contained therein.

Source: Golar LNG via Thomson Reuters ONE

[HUG#1725954]

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PetroCorp Group Inc. Announces Corporate Update and Proposed Private Placement

PetroCorp Group Inc.

NEX BOARD : PCG.H

EDMONTON, ALBERTA--(Marketwired - Aug. 30, 2013) - PetroCorp Group Inc. (NEX BOARD:PCG.H) (the "Corporation") announces today that Larry Patriquin, Garry Wetsch, Martin Bernholtz and Hal Beauclair have tendered their resignations as directors of the Corporation. The new board of directors consists of Andrew Lindzon, David Bernholtz and Myra Bongard (the "New Board"), who have agreed, subject to regulatory approval, to act as directors of the Corporation until the next annual meeting or until a successor has been appointed.

The Corporation also announces that, effective immediately, Andrew Lindzon has replaced Larry Patriquin as President and Chief Executive Officer of the Corporation and David Bernholtz has replaced Randy Fries as Chief Financial Officer of the Corporation. All officer appointments are also subject to regulatory approval.

The following are biographies regarding the members of the New Board and newly appointed officers of the Corporation.

Andrew Lindzon

Andrew Lindzon has been President of Ashlin Technology Solutions Inc. ("Ashlin") since 1985. Ashlin is a Canadian technology solutions provider to Canadian businesses with a subsidiary in the United States which provides the same services to American businesses. Mr. Lindzon is also a director of RYM Capital Corp. and Hudson River Minerals Ltd., a company listed on the TSX Venture Exchange ("TSXV"). Mr. Lindzon obtained his LLB from York University in 1984.

David Bernholtz

David Bernholtz is an Account Manager at Mash+Media Solutions Inc. Mr. Bernholtz is also a director of Pacific Orient Capital Inc., a capital pool company, listed on the TSXV and AH Capital Corp. Mr. Bernholtz graduated from Seneca College with a degree in General Arts & Science as well as Creative Advertising.

Myra Bongard

Myra Bongard has been a real estate sales representative since 1985. Ms. Bongard was associated with Century 21 Heritage Group until 2006 and is currently employed by Right At Home Realty. Ms. Bongard is currently a director of Pacific Orient Capital Inc., a capital pool company, listed on the TSXV. Ms. Bongard was formerly a director of Ribbon Capital Inc., a capital pool company, which completed its qualifying transaction with Selectcore Inc. Ms. Bongard graduated from Bathurst Heights Collegiate in 1965.

The Corporation also announces that it plans to complete a non-brokered private placement of up to 10,000,000 common shares of the Corporation (the "Common Shares") at a price of $0.005 per share for aggregate gross proceeds of up to $50,000 (the "Offering").

The proceeds of the Offering will be used for general working capital purposes. Completion of the Offering is subject to regulatory approval including, but not limited to, the approval of the TSX Venture Exchange Inc. The Common Shares issued will be subject to a four month hold period from the date of issuance pursuant to securities legislation.

Neither the NEX, nor its Regulatory Services Provider (as that term is defined in the policies of the NEX) accepts responsibility for the adequacy or accuracy of this release.

This news release may contain certain forward-looking information and statements, including without limitation, statements pertaining to obtaining necessary approvals from the TSX Venture Exchange. All statements included herein, other than statements of historical fact, are forward-looking information and such information involves various risks and uncertainties. There can be no assurance that such information will prove to be accurate, and actual results and future events could differ materially from those anticipated in such information. The Corporation does not undertake to update any forward-looking information except in accordance with applicable securities laws.

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Americas Petrogas Announces Second Quarter 2013 Results

Operating Netback(1) increases $13.7 million or 234%; Increase in net revenue by 75%; Net income of $5.1 million; $36.7 million of cash, investments and financial assets

CALGARY, ALBERTA--(Marketwired - Aug. 30, 2013) - Americas Petrogas Inc. ("Americas Petrogas" or the "Company") (TSX VENTURE:BOE) announces the Company continued to execute on its investment plan on its oil and gas properties in Argentina.

Summary Financial and Operational Highlights

Selected financial and operational information is outlined below and should be read in conjunction with the Company's condensed interim consolidated financial statements and the related Management's Discussion and Analysis ("MD&A") for the quarter, which have been filed on SEDAR under the Company's profile at www.sedar.com and are also available on the Company's website at www.americaspetrogas.com. All amounts are in Canadian dollars unless otherwise stated.

Net income: $5,121,233 in the second quarter of 2013 compared to a net loss of $4,731,206 for the equivalent period of 2012. This is the second consecutive quarter that the Company has reported profitability. Net revenue: increased by $6,371,527 or 75% compared to second quarter of 2012. Cash position: $36.7 million of consolidated cash, cash equivalents, short-term investments, and available-for-sale financial assets as of June 30, 2013. Oil sales volume: during the second quarter of 2013, the Company continued to produce and sell oil primarily from its Medanito Sur conventional block. During the second quarter of 2013, sales volume averaged 2,398 bopd (net), an increase of 70% over the second quarter of 2012 of 1,409 bopd (net). Operating netback: for the second quarter of 2013, operating netback (excluding Oil Plus benefits) was $44.72 per barrel and operating netback (including Oil Plus benefits) was $89.51 per barrel. For the second quarter of 2012, operating netback was $45.68 per barrel. Oil Plus benefits: during the second quarter of 2013, the Company recognized $11.2 million of Oil Plus benefits (related to production and reserve increases). This is in addition to $3.4 million recognized in the first quarter of 2013 and to $1.3 million recognized in the fourth quarter of 2012. Operating netback (including Oil Plus benefits)(1)Operating netback (excluding Oil Plus benefits) per barrel(1)Operating netback (including Oil Plus benefits) per barrel(1)Net income (loss) attributable to owners of the CompanyWeighted average number of common shares outstanding(3)Cash flow from operating activitiesAverage selling price per barrel

Notes:

"Operating netback" is a non-GAAP measure and is calculated as revenues from oil sales less royalties and production costs. Operating netback is used as an indicator of operating performance, profitability and liquidity. Operating netback (excluding Oil Plus benefits) excludes any Oil Plus benefits credited to production costs. Operating netback (including Oil Plus benefits) is net of any Oil Plus benefits credited to production costs. Operating netback does not have a standardized meaning prescribed by IFRS. It is unlikely for non-GAAP measures to be comparable to similar measures presented by other companies. For the three months ended June 30, 2013, operating netback including Oil Plus benefits was $19,535,145 (calculated as gross oil sales revenue of $17,224,255 less royalties of $2,368,597 plus production costs recovery of $4,679,487). For the three months ended June 30, 2012, operating netback was $5,855,237 (calculated as gross oil sales revenue of $9,729,829 less royalties of $1,245,698 and production costs of $2,628,894). For the six months ended June 30, 2013, operating netback including Oil Plus benefits was $32,701,960 (calculated as gross oil sales revenue of $33,673,901 less royalties of $4,471,378 plus production costs recovery of $3,499,437). For the six months ended June 30, 2012, operating netback was $12,937,395 (calculated as gross oil sales revenue of $21,357,636 less royalties of $3,789,881 and production costs of $4,630,360). "Funds flow from operations" is an additional GAAP measure because it is presented in the consolidated statement of cash flows. Funds flow from operations and funds flow from operations per share are used to analyze operating performance and liquidity. Funds flow from operations is calculated as net cash generated from (used by) operating activities (as determined in accordance with IFRS) before changes in non-cash balance sheet operating items. Funds flow from operations per share is calculated by dividing funds flow from operations by the weighted average number of shares outstanding. Funds flow from operations should not be considered an alternative to, or more meaningful than net cash generated from (used by) operating activities as determined in accordance with IFRS. Funds flow from operations per share should not be considered an alternative to, or more meaningful than earnings (loss) per share as determined in accordance with IFRS. Diluted weighted average number of common shares outstanding is computed by adjusting basic weighted average number of common shares outstanding for dilutive instruments. The number of shares included with respect to options, warrants and similar instruments is computed using the treasury stock method, which assumes any proceeds received by the Company upon exercise of the in-the-money instruments would be used to repurchase common shares at the average market price for the period. For the three and six months ended June 30, 2013, 1,936,583 (three months ended June 30, 2012 - 8,372,168) and 3,359,445 (six months ended June 30, 2012 - 9,970,025) common shares were deemed to be issued for no consideration in respect of options. Working capital is a non-GAAP measure and is calculated as current assets less current liabilities. Working capital is used to assess liquidity general financial strength. Working capital does not have a standardized meaning prescribed by IFRS. It is unlikely for non-GAAP measures to be comparable to similar measures presented by other companies. Working capital should not be considered an alternative to, or more meaningful than current assets or current liabilities as determined in accordance with IFRS.

Second Quarter Highlights and Recent Developments

Ryder Scott Company estimated that the Company has 56.1 Billion Barrels of Oil Equivalent ("BOE") initially in place and 8.3 Billion BOE Recoverable in the Company's nine unconventional shale oil and shale gas properties. The report only considered the Vaca Muerta, Agrio and Los Molles shales. The report did not consider additional zones of interest such as the Quintuco, Tordillo, Mulichinco and others. During the second quarter of 2013, Petrogas Argentina obtained two loans from the Industrial and Commercial Bank of China (Argentina) S.A. in the total amount of AR$50.0 million (approximately $9.5 million). Nine (9) conventional wells were drilled during the second quarter of 2013. Earlier in 2013, drilling on Medanito Sur resulted in the discovery of new production areas, including El Alpataco, El Calden Este, Amilcar and La Meseta. In total, twenty (20) conventional wells were drilled in the first half of 2013. As well, the Company invested $12.8 million in facilities and equipment during the first half of 2013. The Company, in conjunction with its partner, ExxonMobil, continued to conduct long-term production testing on the LTE.x-1 well and continued to analyze data relating to the ALL.x-1 well and ADA.x-1 well. During the second quarter of 2013, the Company made the necessary filings and received the necessary approvals to make a Normal Course Issuer Bid ("NCIB") to buy-back some of its common shares commencing on June 21, 2013 and terminating on June 20, 2014 or such earlier date as all shares which are subject to the NCIB are purchased. Up to the current date, the Company has bought back and cancelled 207,000 common shares for a total cost of approximately $185,000.

"We are pleased with our results this quarter, generating $19.5 million of operating netback at $89.51 per barrel, including Oil Plus benefits, and $5.1 million of net income," said Barclay Hambrook, President and Chief Executive Officer. Mr. Hambrook went on to say, "The results of the Ryder Scott Company report were excellent and this report clearly highlights the large upside potential of Americas Petrogas' Neuquen Basin blocks."

For further information regarding the Company's financial results, financial position and related changes, please see the consolidated financial statements and the related MD&A.

About Americas Petrogas Inc.

Americas Petrogas Inc. is a Canadian company whose shares trade on the TSX Venture Exchange under the symbol "BOE". Americas Petrogas has conventional and unconventional shale oil and gas and tight sands oil and gas interests in numerous blocks in the Neuquén Basin of Argentina. Americas Petrogas has joint venture partners, including ExxonMobil and Apache, on various blocks in the shale oil and gas corridor in the Neuquén Basin, Argentina. Americas Petrogas also owns an 80% interest in GrowMax Agri Corp., a private company involved in the exploration for near-surface potash, phosphates and other minerals, and potential development of a fertilizer project in Peru. Indian Farmers Fertiliser Co-operative Limited (IFFCO) owns a 20% interest in GrowMax Agri Corp. For more information about Americas Petrogas Inc., please visit www.americaspetrogas.com.

This Press Release contains forward-looking information including, but not limited to, the Company's goals and growth, estimates of reserves and resources, production and cash flows, new production areas on the Medanito Sur block, production testing of the LTE.x-1 well, analysis relating to the ALL.x-1 well and ADA.x-1 well, results of the Ryder Scott Company report, the large upside potential of Americas Petrogas' Neuquen Basin blocks, exploration, appraisal and development activities related to conventional and unconventional oil and gas, and other exploration, development and production activities in respect of the projects in Argentina and Peru. The recovery and resources estimates for the Company's properties described in this Press Release are estimates only and there is no guarantee that the estimated resources will be recovered. The actual resources for the Company's properties may be greater or less than those calculated. Additional forward-looking information is contained in the Company's MD&A for this quarter and the Company's Annual MD&A for December 31, 2012, and reference should be made to the additional disclosures of the assumptions, risks and uncertainties relating to such forward-looking information in those MD&A documents.

Forward-looking information is based on management's expectations regarding the Company's future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity (including the timing, location, depth and the number of wells), environmental matters, business prospects and opportunities and expectations with respect to general economic conditions. Such forward-looking information reflects management's current beliefs and assumptions and is based on information, including reserves and resources information, currently available to management. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by the forward-looking information, including but not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production, delays or changes to plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of geological interpretations; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environment risks, extensions of concessions and commitments), the risk of commodity price and foreign exchange rate fluctuations, the uncertainty associated with negotiating with foreign governments and third parties located in foreign jurisdictions and the risk associated with international activity.

Although the forward-looking information contained herein is based upon assumptions which management believes to be reasonable, the Company cannot assure investors that actual results will be consistent with this forward-looking information. This forward-looking information is made as of the date hereof and the Company assumes no obligation to update or revise this information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward-looking information, prospective investors in the Company's securities should not place undue reliance on this forward-looking information.

The term BOE (barrels of oil equivalent) is used in this press release. All calculations converting natural gas to BOE have been made using a conversion ratio of six thousand cubic feet (six "Mcf") of natural gas to one barrel of oil, unless otherwise stated. The use of BOE may be misleading, particularly if used in isolation, as the conversion ratio of six Mcf of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

NEITHER THE 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 THE RELEASE.

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Niko Provides Updates

CALGARY, ALBERTA--(Marketwired - Aug. 30, 2013) - Niko Resources Ltd. ("Niko" or the "Company") (TSX:NKO) is pleased to provide the following updates:

Farm-outs, Non-core Asset Dispositions, and Other Arrangements Update

Niko is pleased to announce that it has executed two sets of agreements which, subject to the required government approvals, will provide proceeds of nearly $40 million.

Farm-out of Grand Prix PSC in Madagascar

Niko has signed a definitive farm-out agreement under which OMV, an integrated international oil and gas company, will earn a 40% interest in the Grand Prix PSC in Madagascar, with Niko retaining a 35% working interest. Closing of the deal is subject to the approval of the Government of Madagascar.

Other Arrangements for Semai V and Kofiau PSCs in Indonesia

Niko has also signed a definitive agreement with Hess Corporation for certain consideration in exchange for assuming a 100% interest in the Semai V PSC, located offshore Papua province in eastern Indonesia. Two wells have been previously drilled in the block, Andalan 1 and 2, with one future commitment well yet to be drilled. Drilling results from these wells indicate hydrocarbon potential remaining on the block. The Company also signed an agreement to increase its working interest (effective prior to the drilling of the Elit-1 well discussed below) to 100% in the Kofiau PSC, also located offshore Papua province, for nominal consideration. The closings of these transactions are subject to the approval of the Government of Indonesia.

Indonesia Exploration Updates

Elit-1 Well

The Elit-1 well, located in the Kofiau PSC offshore Papua province in eastern Indonesia, has been drilled in water depth of 1,335 feet to a total depth of 3,915 feet in 9 days by Diamond Offshore's Ocean Monarch drilling rig, under budget and ahead of schedule. The well encountered 10 feet of gas at the top of a 90 foot sand package and has been plugged and abandoned.

Drilling Operations

Pending the Company's re-evaluation of its go-forward exploration capital spending priorities, the Company has decided to temporarily suspend its drilling program in Indonesia. The Company is working on various options to drill for third parties or to assign the contract for the Ocean Monarch rig and related service contracts to third parties for an extended period of time. The Ocean Monarch is being mobilized to the Makassar Strait area until the decision on the next drilling location has been finalized.

Financing Updates

Credit Facility

The Company is continuing its discussions with its credit facility syndicate banks regarding the re-determination of the borrowing base under its credit facility and is working with the banks on a deferral to September 30, 2013 for the re-determination date and a deferral to October 31, 2013 for any required adjustment to outstanding borrowings to reflect the new borrowing base.

Potential Refinancing of the Credit Facility

The Company is working on options to potentially refinance its credit facility to provide increased funding for its future capital programs.

Forward-Looking Information

Certain statements in this press release constitute forward-looking information. Specifically, this press release contains forward looking information relating to various governmental approvals, proceeds from various agreements, the Company's working interest in various PSCs, the re-determination of the Company's borrowing base under the credit facility and the re-financing of the Company's credit facility. These forward looking statements are based on certain key expectations and assumptions of management, including anticipated market conditions. The reader is cautioned that the assumptions used in the preparation of such forward looking information, although considered reasonable at the time of preparation, may prove to be incorrect and there can be no assurance that the expected proceeds from agreements will occur or occur on terms acceptable to the Company. Actual results achieved may vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors and such variations may be material. Such factors include, but are not limited to: risks associated with market conditions; risks associated with oil and gas operations including equipment failures or accidents; the ability of suppliers and third party contractors to meet commitments; pressure or irregularities in geological formations; and adverse weather conditions. Niko makes no representation that the actual results achieved during the forecast period will be the same in whole or in part as those forecast.

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Blackdog Resources Ltd. Announces Intention to Purchase Two Light Oil Properties in Alberta for $13,000,000

CALGARY, ALBERTA--(Marketwired - Aug. 30, 2013) - Blackdog Resources Ltd ("Blackdog" or the "Company") (TSX VENTURE:DOG) is pleased to announce that it has signed two separate non-binding Letters of Intent (the "LOI's") with two separate arm's length vendors to purchase two light oil properties in Northern Alberta (the "Acquisitions"). Under the terms of the LOI's, Blackdog will purchase both properties for a cumulative total of $13,000,000 in cash. The properties ("Property A and Property B") currently produce between 260-275 boepd (97% light oil).

Blackdog intends to purchase the first property ("Property A") from a Public Company ("Pubco"). Property A has both Operated and Non Operated wells that the Company will purchase. On average the Company will have a 25-50% W.I. in the wells it is purchasing. Property A is located in a different area of Northern Alberta than Property B. The oil produced at Property A comes from 3 different formations, the Granite Wash, Gilwood and Slave Point. All of these oils are high quality light oils that demand prices very close to listed Edmonton Par pricing. The Company has identified multiple low cost, low risk re-entries into existing well bores where it expects to yield high returns for low capital investment.

Transaction Metrics of Property AProved Reserves (NPV10(BT))(1)Proved Plus Probable Reserves (NPV10(BT))(1)Edmonton Par Pricing for 2013(1)2013 Netbacks(3) at 2013 Forecasted Edmonton Par Price(1)Actual August 28, 2013 Edmonton Par Price(4)Derived from Pubco's (as defined below) December 31, 2012 independent reserves evaluation prepared by AJM Deloitte in accordance with National Instrument 51-101 ("NI 51-101") and the COGE handbook. An updated reserves evaluation for Property A will be obtained and prepared in accordance with NI 51-101.Based on July, 2013 field estimates provided by the vendors.Netbacks do not have a standardized meaning under GAAP. Netbacks are determined by deducting royalties, production expenses and transportation and selling expenses from oil and gas revenue. Netbacks are per boe measures used in operational and capital.Allocation decisions from Daily Oil Bulletin August 28, 2013.

Blackdog intends to purchase the second property ("Property B") from a Private Company ("Privco"). Property B is a 6% Non Operated Working Interest ("W.I.") in an emerging light oil play in Northern Alberta. Blackdog will be acquiring a full 6% W.I. in over 300 sections of land, all facilities, pipelines, seismic and other associated assets. The oil produced at this property is also a high quality Gilwood oil that demands prices very close to Edmonton Par pricing. Property B currently has over a dozen producing wells with all wells tied into pipelines for both oil and water shipping and disposal. The property is fully electrified resulting in very low operating costs. In excess of 30 possible future drilling locations have been identified by the Operator of the property. The current production from the property in July, 2013 based on field reports provided by Privco was 105 boepd (95% light oil). Blackdog will be obtaining a reserves evaluation report with respect to Property B prepared in accordance with NI 51-101 in due course.

David A. Corcoran, President of Blackdog stated, "Blackdog is very pleased to have identified and negotiated deals on both of these high quality light oil properties. The Company believes that by assembling multiple producing light oil properties with reduced risk but additional running room for growth and excellent financial metrics, it will be able to attract required funding from financial institutions and investors and enhance shareholder value. The successful closing of these Acquisitions would cause Blackdog to become a larger entity with higher rates of production, stronger cash flows and reserves and provide a clear roadmap for future growth."

Each of the Acquisitions remain subject to completion of due diligence, financing, board approval by both parties and the execution of definitive purchase and sale agreements, as well as approval by the TSX Venture Exchange. Blackdog intends to announce the details of the proposed financing for the Acquisitions in due course. Both Acquisitions are expected to be completed in October 2013.

About Blackdog

Blackdog is a junior oil and gas Company focused on light oil development in South East Saskatchewan and Alberta. The Company currently has 27,166,212 common shares outstanding.

Neither the 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 the accuracy of this release.

Certain information regarding Blackdog in this news release, including whether either or both of the Acquisitions will be completed and the expected timing thereof, as well as the number of possible future drilling locations on Property A, the expected returns on investment in re-entries on Property B and the anticipated assessment of future productive capacity of the properties to be acquired, may constitute forward looking statements under applicable securities laws. Such forward-looking statements necessarily involve a number of substantial known and unknown risks including, without limitation, risks associated with the benefits to be derived from the Acquisitions, general risks associated with oil and gas exploration, development, production, marketing and transportation, loss of markets, volatility of commodity prices, imprecision of reserve estimates, environmental risks, competition from other producers, unexpected decline rates in wells, wells not performing as expected, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Blackdog's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). The forward-looking statements or information contained in this news release are made as of the date hereof and Blackdog does not undertake any obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

"Boepd" means barrels of oil equivalent per day. The term "barrels of oil equivalent" or "boe" may be misleading, particularly if used in isolation. A "boe" conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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Golar LNG Partners L.P.: Interim Results for the Period Ended June 30, 2013

Golar LNG Partners L.P.

oslo : GOLP01

HAMILTON, BERMUDA--(Marketwired - Aug 29, 2013) -

Highlights

* Golar LNG Partners LP ("Golar Partners" or the "Partnership") reports net income attributable to unit holders of $28.0 million and operating income of $44.4 million for the second quarter of 2013

* Generated distributable cash flow of $26.4 million for the second quarter of 2013

* Declared distribution of $0.515 per unit for the second quarter of 2013

* Golar Mazo and Methane Princess drydockings completed

* Refinanced Golar Winter and Golar Grand with a new bank loan facility $225 million term loan and a $50 million revolver

Subsequent events

* Golar Winter drydocking and modification works completed and vessel delivered to new location in Brazil

* Entered into an additional $100 million interest rate swaps

* Golar LNG Limited ("Golar" or "Golar LNG") secures two FSRU contracts that represent attractive near and medium term acquisition prospects

Financial Results Overview

Golar Partners reports net income attributable to unit holders of $28.0 million and operating income of $44.4 million for the second quarter of 2013 ("the second quarter"), as compared to net income attributable to unit holders of $30.3 million and operating income of $45.2 million for the first quarter of 2013 ("the first quarter") and net income attributable to unit holders of $30.2 million and operating income of $45.3 million for the second quarter of 2012(1).

Lower operating results for the second quarter of 2013 compared to the same period in 2012 is due largely to drydocking offhire time incurred in the second quarter of 2013, with none incurred in the comparable period, and increased drydocking cost amortization partly offset by the contribution of the NR Satu and Golar Maria in the second quarter. NR Satu was on hire throughout the second quarter of 2013 but was in the final stages of its FSRU conversion and commissioning during the earlier half of the second quarter of 2012, and, therefore, not generating revenues. Comparable results for 2012 do not reflect the contribution of Golar Maria as this vessel was not under the common control of Golar at the time of her acquisition by the Partnership in the first quarter of 2013.

Operating results for the second quarter are slightly lower than the first quarter primarily due to increased drydocking offhire days and higher drydock cost amortization, partly offset by a full quarter's contribution from Golar Maria, which was acquired on February 7, 2013.

Offhire time for the Golar Winter drydocking and modification work and the Methane Princess drydocking was approximately ten weeks in total. The Golar Mazo also completed its docking during the quarter without incurring offhire due to a drydocking allowance in its time charter. Partly mitigating the impact of the above dockings has been the biennial revision of the Golar Spirit and Golar Winter time charter rates resulting in an increase to hire rates during the quarter. The second quarter drew to a close an intense program of drydockings, the next scheduled drydockings are for Golar Freeze and Golar Grand which are not due until 2015. All other vessels operated well throughout the quarter with overall utilization at 100 per cent.

Following completion of the agreed modification work to Golar Winter and her redelivery to charterers, Golar Partners will receive approximately $24 million in additional revenue spread evenly over the remaining eleven years of the contract. This uplift is before the biennial rate revisions provided for in the charter.

Net interest expenses increased to $11.7 million for the second quarter of 2013 compared to $10.1 million for the first quarter. This is largely due to additional Indonesian witholding tax allocated to interest expense rather than corporation tax. As with the other Indonesian taxes incurred in connection with the vessel concerned, this tax is effectively rechargeable to the charterer.

Other financial items for the second quarter of 2013 recorded a small loss of $0.1 million compared with a gain of $1.1 million in the first quarter. Mark-to- market valuation gains on interest rate swaps were higher by approximately $2.5 million in the second quarter of 2013 compared to the first quarter but this was offset by the write off of deferred financing fees associated with the refinancing of the Golar Winter and Golar Grand leases.

The Partnership's Distributable Cash Flow(2) for the second quarter of 2013 was $26.4 million as compared to $27.6 million in the first quarter.

On July 25, 2013, Golar Partners declared a distribution for the second quarter of 2013 of $0.515 per unit which was paid on August 14, 2013.

Financing and Liquidity

As of June 30, 2013 the Partnership had cash and cash equivalents of $61.1 million and undrawn revolving credit facilities of $70 million. Total debt and capital lease obligations net of restricted cash was $1.0 billion as of June 30, 2013.

Based on the above debt amount and annualized(3) second quarter 2013 adjusted EBITDA(4 )Golar Partners has a debt to adjusted EBITDA multiple of 4.1 times.

In June 2013, the Partnership refinanced the Golar Winter and Golar Grand leases with a new 5 year $275 million loan facility. The facility is split into two tranches, a $225 million term loan and a further $50 million revolver, which remains undrawn as of June 30, 2013. The loan bears interest at LIBOR plus a margin and is repayable in quarterly instalments of $5 million with a final balloon payment of $130 million payable in July 2018.

As of June 30, 2013, Golar Partners had interest rate swaps with a notional outstanding value of approximately $906.5 million (including swaps of notional amount of $227.2 million in connection with the Partnership's bonds) representing approximately 90% of total debt and capital lease obligations, net of restricted cash. The average fixed interest rate of swaps related to bank debt and capital lease obligations is approximately 2.4% as at June 30, 2013. Subsequent to the quarter end the Partnership entered into a further $100 million seven year swap at a fixed rate of 2.16%. As of June 30, 2013 the Partnership had outstanding bank debt of $778 million with average margins, in addition to LIBOR or fixed swap rates, of approximately 2.3%. In addition, the Partnership has bonds of $214 million with a fixed rate of 6.485%.

Outlook

The announcement by Golar LNG of the contracting of two FSRU vessels provides Golar Partners its first two potential acquisitions from Golar LNG's fleet of 13 newbuildings.

The first contract is for the FSRU Igloo, which delivers in the fourth quarter of 2013, and is contracted to Kuwait National Petroleum Company ("KNPC") for an initial period of 5 years. The contract comprises the provision of portside FSRU services for an anticipated nine months of the year together with a three month window where the vessel is free to pursue spot carrier and other short term business opportunities. Winter scheduling of the three month stand-down period together with favourable positioning mean that the vessel should have realistic trading prospects. The contract is set to commence in March 2014 and has a total contract value of approximately USD$213 million covering both capital and operating elements over five years.

The second contract is with the Government of the Hashemite Kingdom of Jordan, represented by the Ministry of Energy and Mineral Resources ("the Government"). The FSRU Golar Eskimo will be moored at a purpose built structure that is to be constructed by the Aqaba Development Corporation off the Red Sea port of Aqaba. The FSRU will connect to the Jordan Gas Transmission Pipeline that delivers natural gas to power plants throughout the Kingdom. Earnings under the ten year contract are due to commence during the first quarter of 2015. Annual EBITDA contribution for the first five years of the contract will be approximately $46 million and approximately $43 million per year for the second five year term. The Government has the option to terminate the time charter after year five, subject to payment of an early termination fee.

With the recent contract announcements by Golar LNG and its remaining newbuild fleet of 11 as yet uncontracted vessels, the Board is confident that Golar Partners can continue to strongly grow its earnings and distributions over the longer term.

With the recent drydockings now completed the Board expects a significant improvement in operating results in the third quarter of 2013 with no drydocking offhire and high operational uptime expected. This will be enhanced by increased charter rates for the Golar Winter and Golar Spirit which were escalated according to the contract during the second quarter and the rate increase on the Golar Winter as a result of the modification work which is expected to take effect during the third quarter. Based on current operational performance of the vessels, the Partnership expects operating income in excess of $50 million in the third quarter.

With the growth opportunities outlined above, the Board remains very excited about the prospects of Golar Partners.

August 29, 2013

Golar LNG Partners L.P.

Hamilton, Bermuda.

Questions should be directed to:

C/o Golar Management Ltd - +44 207 063 7900

Brian Tienzo or Graham Robjohns

(1)Following the acquisition of the Golar Grand and NR Satu from Golar, the comparative results for the second quarter ended 2012 assume that the Golar Grand and NR Satu were wholly owned by the Partnership for the entire period that the vessels have been under the common control of Golar.

(2)Distributable cash flow is a non-GAAP financial measure used by investors to measure the performance of master limited partnerships. Please see Appendix A for a reconciliation to the most directly comparable GAAP financial measure.

(3)Annualized means the figure for the quarter multiplied by 4.

(4)Adjusted EBITDA: Earnings before interest, other financial items, taxes, non- controlling interest, depreciation and amortization. Adjusted EBITDA is a non- GAAP financial measure used by investors to measure our performance. Please see Appendix A for a reconciliation to the most directly comparable GAAP financial measure.

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

Golar Partners Q2 2013 Results: http://hugin.info/147317/R/1725799/575627.pdf

This announcement is distributed by Thomson Reuters on behalf of Thomson Reuters clients. The owner of this announcement warrants that:

(i) the releases contained herein are protected by copyright and other applicable laws; and

(ii) they are solely responsible for the content, accuracy and originality of the information contained therein.

Source: Golar LNG Partners L.P. via Thomson Reuters ONE

[HUG#1725799]

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Blue Water Petroleum Corp. Completes Drilling of Production Well, Begins Drilling New Well

Blue Water Petroleum Corp.

OTCQB : BWPC
BERLIN : BWPC

CENTENNIAL, COLORADO--(Marketwired - Aug. 29, 2013) - Blue Water Petroleum Corp. (OTCQB:BWPC)(BERLIN:BWPC) (the "Company", "we", "us" or "our") announced that they have completed drilling on the # 31122 Tribal well in Big Horn County, Montana. The well was drilled to a total depth of 824 feet, and was successfully cased, cemented, and perforated. The well is the 4th well in a planned 5 well production unit.

The drilling rig has moved onto the location of the fifth well, the # 41122 Tribal, drilling has commenced and surface casing has been set at 80 feet.

The project is scheduled to produce shallow oil by injection of steam in a central well that will drive oil to four surrounding production wells in a 40 acre production unit.

About Blue Water Petroleum Corp.

Blue Water Petroleum Corp. is an oil and gas company that has an agreement to develop shallow oil resources on up to 12,979 leased acres in southeastern Montana. For further information please contact Ellis Martin at 1-888-498-8880.

This press release contains forward-looking statements about the Company and its business, plans, expectations and intentions. Forward looking statements are statements that are not historical facts and include, but are not limited to, statements about the Company's drill plans, expected results and future success. The forward-looking statements in this press release are subject to various risks, uncertainties and other factors that could cause the Company's actual results or achievements to differ materially from those expressed in or implied by forward looking statements. These risks, uncertainties and other factors are identified in the Company's filings with the United States Securities and Exchange Commission.

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Newton Energy Corporation Announces Amendments to Proposed Private Placement

CALGARY, ALBERTA--(Marketwired - Aug. 30, 2013) - Newton Energy Corporation (the "Company" or "Newton") (TSX VENTURE:NTN) announces that further to its press release dated August 28, 2013, the Company amends its previously announced non-brokered private placement from up to 23,000,000 units (the "Units") of Newton at a price of $0.01 per Unit for aggregate gross proceeds of up to $230,000 to up to 17,500,000 Units at a price of $0.015 per Unit for aggregate gross proceeds of up to $262,500 (the "Offering"). All other terms remain the same.

About Newton

Newton holds UK East Midlands assets and is an emerging exploration and production company. Newton is in discussions with several potential partners to facilitate field appraisal and development of the Belvoir Prospect.

ADVISORY

Neither the 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 may contain certain forward-looking information and statements, including without limitation, statements pertaining to receipt of regulatory approval of the Offering. Statements included herein, other than statements of historical fact, including, are forward-looking information and such information involves various risks and uncertainties. There can be no assurance that such information will prove to be accurate, and actual results and future events could differ materially from those anticipated in such information. A description of assumptions used to develop such forward-looking information and description of risk factors that may cause actual results to differ materially from forward-looking information can be found in Newton's disclosure documents on the SEDAR website at www.sedar.com Newton does not undertake to update any forward-looking information except in accordance with applicable securities laws.

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Falcon Oil & Gas Ltd. Announces Its Annual General and Special Shareholder Meeting to Be Held on 30 September 2013

DUBLIN, IRELAND--(Marketwired - Sept. 2, 2013) - Falcon Oil & Gas Ltd. (TSX VENTURE:FO)(AIM:FOG)(ESM:FAC) ("Falcon") announces that its Annual General and Special Shareholder Meeting will be held at O'Callaghan Stephen's Green Hotel, 1-5 Harcourt Street, Dublin 2, Ireland, on Monday 30 September 2013 at 11:00 a.m. (Greenwich Mean Time).

A complete notice and related documents have been sent to the shareholders of record as at 22 August 2013 and are also available on the Canadian System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com and Falcon's website at www.falconoilandgas.com.

About Falcon Oil & Gas Ltd.

Falcon is an international oil & gas company engaged in the acquisition, exploration and development of conventional and unconventional oil and gas assets, with the current portfolio spread between Australia, South Africa and Hungary. Falcon is incorporated in British Columbia, Canada and headquartered in Dublin, Ireland with a technical team based in Budapest, Hungary.

For further information on Falcon Oil & Gas Ltd. please visit www.falconoilandgas.com.

Neither the 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.

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