Sterling Resources Announces 2014 Operating and Financial Results, Resources Disclosure and Future Cost Information

CALGARY, April 17, 2015 /CNW/ - Sterling Resources Ltd. (TSXV: SLG) ("Sterling" or the "Company"), an international oil and gas company with exploration, development and production assets in the United Kingdom, Romania, and the Netherlands, is pleased to announce operating and financial results for the year ended December 31, 2014. Unless otherwise noted all figures contained in this release are denominated in US dollars.

Financial Summary

Net income for the year ended December 31, 2014 was $111.0 million ($0.33 per common share) compared to a net loss of $31.2 million ($0.11 per common share) for the year ended December 31, 2013.  The transformation from net loss to net income is largely attributable to (1) the recognition of a deferred tax asset, (2) income from production from the Breagh gas field and (3) a gain on disposal relating to a carve-out transaction in Romania.  The net income is however reduced by impairment costs principally relating to Romania and Cladhan.

  • Operating netback of $57.3 million came from $80.3 million of revenue less $8.8 million of third party entitlement and $14.1 million of operating expenses ($9.37 per barrel of oil equivalent).
  • Revenue from the Breagh gas field during 2014 totaled $80.3 million, on sales gas production of approximately 8.9 billion cubic feet at an average realized price of 50.8 pence per therm ($8.19 per thousand cubic feet), sales of 3,260 tonnes of condensate (27,225 barrels) at an average price of £425 ($701) per tonne, and other revenues including receipts from natural gas financial derivative instruments of $5.2 million.  Material production from Breagh commenced in October 2013, and revenue for 2013 totaled $3.5 million on sales gas production 0.9 billion cubic feet at an average price of $10.27 per thousand cubic feet. 
  • The deferred tax asset has been increased to $194.0 million from the $144.5 million initially recognized in the first quarter of 2014 mainly due to tax losses in the subsequent nine month period ended December 31, 2014 and further allowances for ring fence expenditure supplement partly offset by foreign exchange movements.
  • During January 2014 the Company completed a sale and purchase agreement with ExxonMobil and OMV Petrom representing the sale of a 65 percent interest in a sub-divided portion of block 15 Midia in the Romanian Black Sea as originally announced in October 2012.  This carve-out transaction resulted in a gain of $27.3 million, partially offset by $4.3 million of taxes paid.
  • Non-cash items in the Income statement included charges of $31.4 million on depletion, depreciation and amortization, and $80.6 million of impairment costs. $22.8 million of this impairment related to Cladhan as a result of lower commodity prices and capital overruns, with the balance as a result of exiting or reducing our exposure to exploration, appraisal and early development stage assets that cannot easily be financed.  
  • Financing costs during 2014 totaled $26.2 million primarily attributable to borrowing costs of $25.1 million on the bond expensed from the date Breagh production commenced in October 2013, and $0.9 million of interest expense related to the Cladhan funding arrangement which has been capitalized as borrowing costs.  The remaining financing costs of $1.1 million include accretion of the discount on decommissioning obligations and have increased in the period due to greater decommissioning obligations on the Breagh and Cladhan developments. 
  • Expenditure on assets consisted of:
    • $55.9 million of additions to property, plant and equipment, relating to Breagh and Cladhan, the latter through the Cladhan funding arrangements.
    • $35.8 million of additions to exploration and evaluation assets, mostly relating to the Crosgan well in the UK and an exploration well and related work in Romania of which $7.8 million was written off as dry-hole expense on the block 27 Muridava licence in Romania.  
    • $5.5 million of pre-licence and other exploration costs were expensed during 2014. Of the $5.5 million total, $2.5 million was attributable to licences in the UK, $1.1 million attributable to Romania, and $1.9 million attributable to the Netherlands and other international ventures.  
  • For the year ended December 31, 2014 the Company recorded a foreign exchange loss of $11.3 million due to the strengthening of the US dollar during the third and fourth quarters of 2014, which followed two quarters of a weak US dollar relative to the UK pound.  The senior secured bond issued by the UK subsidiary is denominated in US dollars and the UK pound is Sterling's functional currency.   

Cash and cash equivalents were $17.7 million at December 31, 2014 compared to $34.7 million at year-end 2013.

As at December 31, 2014 the Company had a net working capital deficit of $30 million compared to a net working capital surplus of $2.2 million as at December 31, 2013. The Company does not expect to have sufficient funds to make a required $32.7 million payment to bondholders and to make the first monthly transfer (following the temporary suspension agreed in the December 2014 bond amendments) of $5.3 million to the DSRA on April 30, 2015. The estimated shortfall is approximately $27 million including the requirement to maintain a minimum $10 million UK liquidity level.  Accordingly the Company is currently considering a range of financing options including seeking a further set of bond amendments.  At the end of the first quarter of 2015, the Company had cash and cash equivalents of $17.7 million (and negligible restricted cash).

Cash proceeds of $32.5 million, less any tax liabilities, from the sale of the Company's Romanian business (the "Romanian Sale") are expected to be received upon completion of the transaction around the end of June of 2015 and thus will not be available to assist in making the payment to bondholders and in funding the monthly DSRA transfer on April 30, 2015. To address the Company's longer term financing needs, the Company is continuing discussions with a number of potential purchasers for the sale of 10-15 percent interest in the UK Breagh gas field and progressing a potential refinancing of the bond and/or incremental financings.  In addition, a number of potential corporate transactions are being discussed.

Operational Summary

Performance at the UKNS Breagh gas field continues to improve, with first quarter 2015 total field sales gas volumes of 11.1 billion cubic feet (Bcf) (3.3 Bcf net to Sterling) equating to an average rate of 123 million standard cubic feet per day ("MMscf/d") (36.9 MMscf/d net to Sterling). Average production uptime over the year to date was 96 percent. New 3D seismic has been acquired across the Breagh field area for use in ongoing development of the field including the remaining Phase 1 drilling program and potential Phase 2 development planning.

During 2015 we intend to move forward  with a number of initiatives  in the UK North Sea including: (1) moving forward with Breagh Phase 2 planning and optimization reflecting the drilling, hydraulic stimulation and production history of Phase 1; (2) continued development  of the Cladhan field with initial production expected to begin in September 2015; (3) farm-out of the UK licences containing the Niadar and Ossian/Darach prospects, and (4) drill an appraisal well, for which nearly all of the costs will be carried under a farm-out agreement, on either the Evelyn or Belinda oil discoveries. 

In the Netherlands, acquisition of 500km2 of 3D seismic data over the F17a and F18 blocks (Sterling 35 percent, operator) was completed in June of 2014 with processing and interpretation expected to be completed by the middle of 2015.  The seismic acquired is over the oil discoveries and prospects in the Jurassic and Early Cretaceous horizons,  in order to improve reservoir understanding and assist in evaluating new exploration potential and existing development options. The 3D seismic survey acquired during 2012 for the E03 and F01 blocks (Sterling operator with 30 percent) is currently being evaluated. 

 "Despite a very challenging macroeconomic environment we continue to have faith in the long term potential of the North Sea assets, " stated Sterling's Chief Executive Officer Jake Ulrich. "We were pleased to announce the sale of the Romanian business in March and expect the transaction to close around the end of June. Discussions continue with Sterling's bondholders to address the pending April 30, 2015 payment and we continue to discuss the sale of a portion of Sterling's 30 percent interest in the Breagh field with a number of parties.  Longer term, we intend to close the value gap between the current share price and a fair valuation through a focus on UK production and tax efficiency, backed by rigorous capital allocation,"  added Mr. Ulrich. 

Reserves and Resources Summary

Sterling announced the filing of its annual Reserves disclosure pursuant to National Instrument 51-101 ("NI 51-101") on March 27, 2015.  An update of the Company's Contingent and Prospective Resources has since been completed by the Company's Reserves evaluator RPS Energy for each of the Sterling Resource assets and presented below with the Company's 2014 Reserves statement. 

Contingent 2C Resources have increased by 7 percent due to the reclassification of reserves to Contingent Resources for the Breagh Field Phase 2 development.  Best Estimate (P50) Prospective Resources have decreased by 18 percent due to several factors: a decrease due to the Muridava dry-hole, downgrade of the Oligocene fan in Block 25, and increases from new prospects identified in the Midia Block offset by a smaller but better definition of Ioana downdip (Zara) prospect in Midia Block 15.  These changes in Block 15 and 25 arise from the interpretation of the fast track volume of the 3D seismic data acquired during late 2013 and early 2014.


Company Share Gross(2) and Net Oil
and Gas Reserves
as at December 31, 2014
(MMboe)(4)


Summary of Net Present Value
of Future Net Revenue
Before Income Tax(7)
as at December 31, 2014
($million)


Proved

Proved +

Probable

Proved +

Probable +

Possible(3)


Proved

Proved +

Probable

Proved +

Probable +

Possible(3)

Breagh (5)

30.0%

18.0

22.7

30.2


377

496

675

Cladhan (6)

13.8%(13)

0.1

0.5

0.8


4

13

30

Company Total (8,9)

18.1

23.1

31.0


381

509

705

Company Resources Summary (12,14)


Unrisked Contingent (10)(12)
Resources

Company Share


Unrisked Prospective (11)(12)
Resources

Company Share


1C

2C

3C


Low

Best

Estimate

High



P(90)

P(50)

P(10)


P(90)

P(50)

P(10)

Gas

Bscf

314

416

525


1,647

2,279

3,179

Oil

MMbbls

20

25

33


24

52

147

Company Resources Change Summary from December 31, 2013(12,14)


Unrisked Contingent (10)(12)
Resources

Company Share


Unrisked Prospective (11)(12)
Resources

Company Share


1C

2C

3C


Low

Best

Estimate

High



P(90)

P(50)

P(10)


P(90)

P(50)

P(10)

Gas

Bscf

20.0

26.0

41.0


(292.0)

(490.0)

(866.0)

Oil

MMbbls

(0.1)

(0.1)

(0.1)


0.1

0.2

-

Notes:

1

Estimates of Reserves and Future Net Revenue have been made assuming the development of each property in respect of which the estimate is made will occur, without regard to the likely availability to the Company of funding required for that development. Totals may differ due to rounding.



2

Gross before royalties.



3

Possible Reserves are those additional reserves that are less certain to be recovered than Probable Reserves.  There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of Proved plus Probable plus Possible Reserves. In this instance the gross values are the same as the net values because the royalty is zero.



4

MMboes 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. 



5

Breagh Reserves are predominantly gas. 



6

Oil 



7

Discounted at 10 percent per annum.



8

Company Reserves totals are arithmetic aggregations of multiple estimates, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give particular attention to the estimates of individual classes of Reserves and appreciate the differing probabilities of recovery associated with each class under a specific set of economic conditions:

  • At least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved reserves (1P);
  • At least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves (2P); and
  • At least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable plus Possible reserves (3P).


9

The estimates of Reserves and Future Net Revenue for individual properties may not reflect the same confidence level as estimates of Reserves and Future Net Revenue for all properties, due to the effects of aggregation.



10

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.  Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets.  It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.  There is no certainty that it will be commercially viable to produce any portion of the resources.

 

The P(50) or 2C is considered to be the best estimate of the quantity that will actually be recovered. If probabilistic methods are used there should be at least a 50 percent probability P(50) that the quantities actually recovered will equal or exceed the estimate. Similarly, the 1C or P(90) and 3C or P(10) represent the low and high estimates respectively.



11

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.  Prospective resources have both an associated chance of discovery and a chance of development.  There is no certainty that any portion of the resources will be discovered.  If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.

 

In relation to the relative uncertainty of recoverability of resources, a Best Estimate Prospective resources quantity is considered to be the best estimate of the quantity that will actually be recovered.  It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate.  There should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the Best Estimate. Similarly, the Low Estimate or P(90) and High Estimate or P(10) represent the low and high estimates respectively.



12

 

 

 

Company Resource totals shown by Resource category are statistical aggregates of unrisked Resources at a company level. For Contingent Resources the statistical aggregates assume no dependencies between discoveries and for Prospective Resources these statistical totals assume no dependencies between prospects.



13

The Company's current equity interest is 2.0 percent, but this is expected to revert to 13.8 percent in 2018 upon pay-out of a repayable carry arrangement with TAQA.



14

Contingent Resources and Prospective Resources volumes are stated in terms of sales quantity volumes.

The Company's hydrocarbon reserves and resources were independently evaluated by RPS effective December 31, 2014 in accordance with the Canadian Oil and Gas Evaluation Handbook ("COGEH") reserves definitions and evaluation practices and procedures, as specified by NI 51-101.  There is no certainty that it will be commercially viable to produce any portion of the Reserves.  The evaluation uses the RPS forecast prices and costs as at December 31, 2014. 

Complete details regarding Sterling's reserves for the year ended December 31, 2014 and in a format specified by NI 51-101 can be found on SEDAR at www.sedar.com or on the Company's website www.sterling-resources.com

Further details regarding Sterling's Contingent and Prospective Resources for the year ended December 31, 2014 are provided in the Company's Annual Information Form (AIF) which can be found on SEDAR at www.sedar.com or on the Company's website www.sterling-resources.com

Executive summaries of the reserves and resources reports for the Breagh and Cladhan fields in the UK North Sea as at December 31, 2014 have also been filed on SEDAR and made available on the Company's website www.sterling-resources.com.  The executive summaries were prepared by the Company's independent reserves evaluator RPS Energy and are dated April 14, 2015. The reserves, resource description and associated valuations in these executive summaries are consistent with the Statement of Reserves Data and Other Oil and Gas Information (form NI 51-101F1) filed on March 27, 2015 with an effective date of December 31, 2014. Contingent Resources described in these reports form part of the Company's portfolio as described within the AIF.

Adjusted Breagh Production Profiles and Capex Phasing

Since the date of preparation of the cash flow tables within the RPS End-2014 Breagh Executive Summary Report, the operator RWE Dea has provided further details of expected well timings and hydraulic stimulation program design.  Wells are expected to be drilled 3 to 4 months later and batch hydraulic stimulation of wells is assumed (on two new wells and one existing well in 2016, and on two new wells and one existing well in 2017).  Sterling's management has remodeled the Proved plus Probable (P50) production profiles and associated capital expenditures ("capex") phasing for Phase 1 of the development to reflect the operator's guidance, without initially changing the RPS reserves estimate or total capex figures.  Note that the annual average production rates assume a 3-week shutdown in June 2015 and average field uptime of 92 percent for the remainder of the year.  For the last three quarters of 2015, we expect average production of 28.9 MMscf/d net to Sterling.

In addition, Sterling has adjusted the capex phasing to be on a cash basis, rather than an accruals basis.  This has the additional impact of increasing overall capex by $1 million (from $126 million to $127 million, net to Sterling, from the start of 2015), since it now captures some cash payments made in the first quarter of 2015 resulting from 2014 activities.  The revised production and capex profiles for the next five years for Breagh Phase 1 (including $3 million of pre-sanction expenditures on Phase 2 in 2015) are as follows:


Capital expenditures ($million)

Net Production (MMscf/d)(1)

Year

RPS

End 2014(2)

Sterling

adjusted

RPS

End 2014(2)

Sterling

adjusted

2015

52

10

32.2

30.8

2016

65

69

44.6

28.4

2017

9

48

47.3

49.6

2018



38.9

52.3

2019



29.0

39.1

Total

126

127



Notes:

1

Production is Proved plus Probable (P50) sales gas.  In addition, condensate is expected to be produced at a ratio of 3.3 barrels per million cubic feet of gas.



2

RPS End-2014 Breagh Executive Summary Report; assumes 12 wells and 2 sidetracks plus hydraulic stimulations of existing wells

Future G&A and E&A Costs

The Company has made decisive steps to reduce its future general and administrative costs and employee expense costs (in aggregate, "G&A Costs"), to respond to the current low commodity price environment and its challenges meeting required bondholder payments.  This has been achieved by a reduction of UK staff numbers by 30 percent achieved in the first quarter of 2015, office moves in London (completed) and Aberdeen (later in April 2015); in addition the planned Romanian Sale (which includes the Sterling's Bucharest office and staff) will lead to a further reduction.  Because of redundancy costs and an ongoing high level of legal and other advisory costs, total G&A Costs (including such additional costs) is expected to be around $13 million net of which $9 million will be spent in the last three quarters of 2015 (note this is not an IFRS measure). Going forward, the Company expects to have lower business development and professional advisor costs from 2016 onwards. In aggregate, the Company expects total G&A Costs to drop on a gross basis to $8.5 million per annum for 2016 onwards and on a net basis (after allocations and partner recoveries) to $6.5 million per annum, approximately.

Exploration and Appraisal ("E&A") costs over the next few years should be sharply reduced as a result of the planned Romanian Sale.  The only material E&A costs remaining relate to the UK offshore, where Sterling has three outstanding commitment wells, one each on block 21/30f (Sterling 20 percent interest; well yet to be identified, transferred from Beverley prospect), block 49/19b (Sterling 100 percent, Niadar prospect) and blocks 42/3a, 42/4, 42/5 (Sterling 100 percent, Ossian and Darach prospects).  The first (formerly Beverley) well cost is largely funded by existing carry arrangements.  The second well and third wells (Niadar and Ossian/Darach) are expected to be drilled with a net paying interest of 25 percent following a farm-out which Sterling is seeking to achieve prior to drilling.  On this basis, future net E&A costs are as follows:

Period

Net E&A costs
$ million

Comments (major work items)

2015 (Apr-Dec)

1

No material activity

2016

5

UK Sheryl well abandonment, UK Belinda/Evelyn

appraisal well, UK Niadar exploration well

2017

6

UK Ossian Darach exploration well

Sterling Resources is a Canadian-listed international oil and gas company headquartered in Calgary, Alberta with assets in the United Kingdom, Romania, and the Netherlands. The common shares are listed and posted for trading on the Toronto Stock Exchange Venture (TSX-V) exchange under the symbol "SLG".

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

Filer Profile No. 00002072               

Forward-Looking Statements

All statements included in this news release that address activities, events or developments that Sterling expects, believes or anticipates will or may occur in the future are forward-looking statements.  In addition, statements relating to expected production, reserves, costs and valuation are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future.

These forward-looking statements involve numerous assumptions made by Sterling based on its experience, perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances.  In addition, these statements involve substantial known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other-forward looking statements will prove inaccurate, certain of which are beyond Sterling's control, including: the impact of general economic conditions in the areas in which Sterling operates, civil unrest, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, fluctuations in commodity prices, foreign exchange or interest rates, stock market volatility and obtaining required approvals of regulatory authorities. In addition there are risks and uncertainties associated with oil and gas operations.  Readers should also carefully consider the matters discussed under the heading "Risk Factors" in the Company's Annual Information Form.

Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur.  Sterling's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements.  These statements speak only as of the date of the news release. Sterling does not intend and does not assume any obligation to update these forward-looking statements except as required by law.

Financial outlook information contained in this news release about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available.  Readers are cautioned that such financial outlook information contained in this news release should not be used for purposes other than for which it is disclosed herein.

SOURCE Sterling Resources Ltd.

For further information: visit www.sterling-resources.com or contact: Jacob Ulrich, Chief Executive Officer, Phone: +1 (403) 237-9256, jake.ulrich@sterling-resources.com; David Blewden, Chief Financial Officer, Phone: +1 (403) 237-9256, david.blewden@sterling-resources.com; George Kesteven, Manager, Corporate and Investor Relations, Phone: (403) 215-9265, Mobile: (403) 519-3912, george.kesteven@sterling-resources.com

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