News 2018

27 Nov 2018

Financial Results for the Nine Months ended 30 September 2018


London, 27 November 2018

Financial Results for the Nine Months ending 30 September 2018

Nostrum Oil & Gas PLC (LSE: NOG) (“Nostrum”, or “the Company”), an independent oil and gas company engaging in the production, development and exploration of oil and gas in the pre-Caspian Basin, today announces its financial results in respect of the nine-month period ending 30 September 2018.



  • Revenue of US$311.4 million (9M 2017: US$303.7 million)

  • Net operating cash flows1 of US$151.3 million (9M 2017: US$131.7 million)

  • EBITDA2 of US$187.7 million (9M 2017: US$171.5 million)

  • EBITDA margin of 60.3% (9M 2017: 56.5%)

  • Closing cash3 for the period of US$102.4 million

  • Total debt of US$1,107.4 million and net debt of US$1,005.0 million as at 30 September 2018


  • 9M 2018 average sales volumes of 30,523 boepd (9M 2018 field production: 31,757 boepd)

  • 42 wells currently producing at the Chinarevskoye field - 23 oil wells and 19 gas-condensate wells

  • The third Gas Treatment Unit ("GTU3") to be mechanically complete by the end of December 2018 with commissioning to be finished in 2019 at an extra cost of US$30 million.

Kai-Uwe Kessel, Chief Executive Officer of Nostrum Oil & Gas, commented:

Q3 saw the first quarter-on-quarter increase in the Company’s sales volumes since Q1 2017. Over that period, we have faced unexpected challenges in our primary gas condensate producing reservoir (Biyski North-East) with increased water inflow to existing wells on the flanks of the structure. In addition, the first production well (224) drilled in the reservoir this year, also a flank well, encountered water. The combined effect of these events and the natural decline have reduced forecast average daily sales volumes from the main producing reservoir by more than 10,000 boepd over the last 18 months. Furthermore, operations at well 234 targeting 92m barrels of probable reserves in the West of the field (Biyski West) are currently under technical review following a wellbore collapse during the final stages of drilling.

We are continuing to evaluate the water issues in the Biyski North-east reservoir and also the best way forward to complete the multi-frac appraisal well 234 in the West of the field. The technical work required to be able to move forward with further drilling activities in both of these areas will take approximately 9-12 months. As a result, the drilling programme for H1 2019 will focus on the Northern area of the field where we will look to appraise and develop the discoveries made in 2017 and 2018 with well 40 and well 724.

With drilling in H1 2019 just focusing on the Northern area we will be conducting the 2019 drilling programme with only two rigs. With two rigs on site for 2019 we will not be able to drill as many wells as we had previously forecast. In addition, the Northern area is not yet fully appraised so carries greater uncertainty in predicting potential production volumes. As a result we are changing our approach to production guidance so as not to include any appraisal wells to be drilled in 2019. This means that the average forecast field production for 2019 will be 30,000 boepd corresponding to sales volumes of approximately 28,000 boepd. (The difference of 2,000 boepd between the field production and sales volume is largely the amount of produced gas that is consumed within our extensive processing facilities).

From a financial perspective the Company maintains a solid cash position due to continued cost reduction across the business and improved prices for our sales products during 2018. At the close of Q3 2018 we had US$102m of cash on our balance sheet with a large US$64m receivables balance due in October from product sales, including two cargos of condensate. At the end of November, we expect to have over US$130m of cash on our balance sheet following the unwind of this receivables balance. The Company will aim to hold over US$100m of cash on our balance sheet throughout 2019. We continue to look at hedging options to help reduce any exposure to falls in the oil price during 2019. Capital preservation during 2019 needs to remain a priority for the Company while we work through the challenges we face at the Chinarevskoye field.

Sales volumes
The sales volumes split for 9M 2018 was as follows:


9M 2018 sales volumes


9M 2018 Product Mix (%)

Crude Oil & Stabilised Condensate



LPG (Liquid Petroleum Gas)



Dry Gas






Q3 2018 Drilling

  • Currently three rigs operating on the Chinarevskoye field with wells 228 and 231 nearing completion and expected to come on stream in the next six weeks. In addition one new appraisal well has been spudded (well 703) to target the Vorobyovski horizon in the Northern part of the licence area.

  • Workover activity continued in Q3 2018 on well 45 on an Electric Submersible Pump (ESP) replacement and to repair the annulus in well 40.

2019 Drilling and sales volumes guidance

  • In 2019 the number of active drilling rigs will be reduced from three to two rigs.

  • With two rigs we will be able to drill up to six wells during 2019.

  • The first two wells will be in the Northern area of the field around well 40.

  • The location for additional wells will be provided after we have more data from the wells currently being drilled.

  • For 2019 production guidance we are assuming a base case of just the existing producers that will be on line at the end of 2018. Given the fact we are not drilling in proven areas of the field and the range of possible outcomes from the Northern wells is extremely wide we have decided not to include them in our guidance figures. Therefore taking in to account two new producers in the next six weeks and then the natural decline of the field, we are guiding average production of 30,000 boepd in 2019 corresponding to sales volumes of 28,000 boepd. The difference of 2,000 boepd between the field production and sales volumes is largely the produced gas that is used as fuel within the production facility and is expected to increase relative to previous years as we start up GTU3.

  • Beyond 2019 we are not in a position to guide until we have completed the drilling in the Northern area and received the final technical review on the Biyski West and North-East reservoirs.

  • On the Trident licences we received an extension of Darinskoye licence by four years until end of the year 2022 and are in the process of applying for a further extension of the Rostoshinskoye licence for four years.

Progress on the development of GTU3

GTU3 is forecast to be mechanically complete in December 2018. The storage facilities for Liquefied Petroleum Gas are finished and ready for use. The central heating system has also been successfully commissioned. The compressor buildings are finished, and the compressors are ready for commissioning. The remaining areas awaiting completion are all linked to a delay in welding at the site. This has been due to a lack of skilled welders being available over the summer to perform welding operations on the stainless steel pipes. Given the delays we will not be able to start commissioning until Q1 2019. Initial estimates for the cost of fully commissioning the plant following mechanical completion, including remaining retention amounts, is an additional US$30 million.

The below figures reflect all future cash payments expected to be made (excluding VAT) on GTU3 to achieve mechanical completion as at 30 September 2018.

Remaining GTU3 Mechanical completion Cash Spend (excl VAT) as at 30 September 2018

US$13.3 million

Significant events after the reporting period

Nostrum is pleased to announce that Mr Atul Gupta, who has served as the Company’s Chairman since 25 April 2017, has been appointed by the Board as Executive Chairman as of 27 November 2018.

Mr Gupta is a UK national who was appointed as a director of the Company on 30 November 2009 and as Chairman of the Audit Committee on 31 December 2016. Mr Gupta has over thirty years of upstream oil and gas industry experience, including at Charterhouse Petroleum, Petrofina, Monument and previously as the CEO of FTSE-250 listed Burren Energy plc until its sale to ENI in 2008. Mr Gupta graduated from Cambridge University with a degree in Chemical Engineering and Heriot Watt University with a Masters degree in Petroleum Engineering.

Effective upon his appointment as Executive Chairman Mr Gupta has stepped down from the Board’s Nomination and Governance Committee.

Conference call

Nostrum’s management team will present the 9M 2018 Financial Results and will be available for a Q&A session with analysts and investors today at 14.00 pm GMT, 27 November 2018. If you would like to participate in this call, please register by clicking on the following link and following instructions: Results Call

If you are unable to access the registration link please use the following:

Download: 9M 2018 Results Presentation

Download: 9M 2018 Financial Statements

Disclosure of inside information in accordance with Article 17 of Regulation (EU) 596/2014 (16 April 2014) relating to Nostrum Oil & Gas PLC and Zhaikmunai LLP

LEI: 2138007VWEP4MM3J8B29

Further information

For further information please visit

Further enquiries

Nostrum Oil & Gas PLC – Investor Relations

Kirsty Hamilton-Smith

Amy Barlow

+44 203 740 7433

Instinctif Partners - UK

David Simonson

George Yeomans

+ 44 (0) 207 457 2020

Promo Group Communications – Kazakhstan

Asel Karaulova

Irina Noskova

+ 7 (727) 264 67 37

Notifying person

Thomas Hartnett

Company Secretary

About Nostrum Oil & Gas

Nostrum Oil & Gas PLC is an independent oil and gas company currently engaging in the production, development and exploration of oil and gas in the pre-Caspian Basin. Its shares are listed on the London Stock Exchange (ticker symbol: NOG). The principal producing asset of Nostrum Oil & Gas PLC is the Chinarevskoye field, in which it holds a 100% interest and is the operator through its wholly-owned subsidiary Zhaikmunai LLP. In addition, Nostrum Oil & Gas holds a 100% interest in and is the operator of the Rostoshinskoye, Darinskoye and Yuzhno-Gremyachinskoye oil and gas fields through the same subsidiary. Located in the pre-Caspian basin to the north-west of Uralsk, these exploration and development fields are situated approximately 60 and 120 kilometres respectively from the Chinarevskoye field.

Forward-Looking Statements

Some of the statements in this document are forward-looking. Forward-looking statements include statements regarding the intent, belief and current expectations of the Partnership or its officers with respect to various matters. When used in this document, the words “expects,” “believes,” “anticipates,” “plans,” “may,” “will,” “should” and similar expressions, and the negatives thereof, are intended to identify forward-looking statements. Such statements are not promises or guarantees, and are subject to risks and uncertainties that could cause actual outcomes to differ materially from those suggested by any such statements.

No part of this announcement constitutes, or shall be taken to constitute, an invitation or inducement to invest in the Company or any other entity, and shareholders of the Company are cautioned not to place undue reliance on the forward-looking statements. Save as required by the Listing Rules and applicable law, the Company does not undertake to update or change any forward-looking statements to reflect events occurring after the date of this announcement.

9M 2018: Nostrum Financial Results

In millions of US$ (unless mentioned otherwise)

9M 2018

9M 2017


Variance in %











EBITDA margin (%)





In millions of US$ (unless mentioned otherwise)

9M 2018

H1 2018


Variance in %

Cash Position





Net Debt4





Revenue, EBITDA and Profit/Loss for the Period

Revenue from sales of crude oil, stabilised condensate, LPG and dry gas over the period amounted to US$311.4 million, up 2.5% on the same period last year due to higher sales prices. EBITDA was US$187.7 million with an EBITDA margin of 60.3%. Profit for the period was US$12.4 million.

Cost of sales

The cost of sales was US$125.8 million, a decrease from the 9M 2017 figure of US$131.2 million. This is partially due to reductions in depreciation, repair and maintenance, other transportation costs and materials and supplies.

Cash resources and Net debt

The Group ended the period with US$102.4 million in cash and cash equivalents4 (H1 2018: US$134.5 million). Net debt4 at the end of the period was US$1,005.0 million (H1 2018: US$993.4 million).


On 4 January 2018, Nostrum entered into a hedging contract equating to production of 9,000 barrels of oil per day. The hedging contract is a zero-cost capped collar with a floor price of US$60.0. The Group has covered the cost of the floor price by selling a number of call options with different strike prices for each quarter; Q1:US$67.5; Q2:US$64.1; Q3:US$64.1; and Q4:US$64.1. The amount of upside given away has been capped through the purchase of a number of call options with different strike prices: Q1:US$71.5; Q2:US$69.1; Q3:US$69.6; and Q4:US$69.6. There were no upfront costs to the Company for the hedging contract. The hedging contract matures on 31 December 2018 and is settled in cash on a quarterly basis.

The average Brent price during Q1 2018 resulted in no settlements taking place between Nostrum and its hedging counterparty during this period (Q1 2018 average Brent price = US$67.2/bbl, Q1 2018 low strike price =US$67.5/bbl). During Q2 2018 the Company was required to make a payment of US$4.1 million as the average Brent price was above the higher call strike price (Q2 2018 average Brent price = US$75.0/bbl, Q2 2018 high strike price = US$69.1/bbl. During Q3 2018 the Company was required to make a payment of US$4.6 million as the average Brent price was above the higher call strike price (Q3 2018 average Brent price = US$75.8/bbl, Q3 2018 high strike price = US$69.6/bbl). The Company remains hedged on 9,000 barrels of oil per day at a floor price of US$60.0 until the end of the year.

1 IFRS term based on indirect cash flow method

2 Defined as the results of operating activities before depreciation and amortisation, share-based compensation, fair value gains and losses on derivative instruments, foreign exchange losses, finance costs, finance income, non-core income or expenses and taxes, and includes any cash proceeds received or paid out from hedging activity

3 Defined as cash and cash equivalents including current investments and including restricted cash

4 Defined as cash and cash equivalents including current investments and including restricted cash