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Press release from CNW Group

Valeura announces third quarter 2013 financial and operating results

Wednesday, November 13, 2013

Valeura announces third quarter 2013 financial and operating results

16:58 EST Wednesday, November 13, 2013

CALGARY, Nov. 13, 2013 /CNW/ - ("Valeura" or the "Corporation") (TSX: VLE) is pleased to report highlights of its unaudited financial and operating results for the three and nine month periods ended September 30, 2013 and to provide an update on subsequent developments. The complete quarterly reporting package for the Corporation, including the unaudited financial statements and associated management's discussion and analysis, has been filed on SEDAR at www.sedar.com and posted on the Corporation's website at www.valeuraenergy.com.

Q3 2013 RESULTS AT A GLANCE

  • Sales up 17% to 1,011 boe/d (net)

  • Funds flow from operations up 73% to $3.1million

  • Operating netback $45.07 per boe

  • 10 additional re-entry fracs completed in new Mezardere slope fan play

  • Two-well horizontal drilling/multi-stage fracing pilot completed in Teslimkoy/Kesan

(See below for definitions and advisories)

OPERATIONAL HIGHLIGHTS

  • Corporate petroleum and natural gas sales in the third quarter of 2013 averaged 1,011 barrels of oil equivalent per day ("boe/d") (net), which was 17% higher than sales in the second quarter of 2013 of 862 boe/d. Turkish net production in the third quarter averaged 967 boe/d, including 5.7 million cubic feet per day ("MMcf/d") of natural gas and 16 barrels of oil per day ("bopd"). Canadian production averaged 44 boe/d.

  • The exit rate for the quarter, as measured by corporate petroleum and natural gas sales in September 2013, was 1,022 boe/d (net). Corporate sales to date in the fourth quarter have averaged approximately 1,140 boe/d (net) reflecting continued growth in Turkish gas production from the Thrace Basin.

Thrace Basin - TBNG-PTI Joint Venture Lands (Valeura 40%)

  • Drilled and frac'd the second horizontal well BTD-4H in a two-well horizontal drilling pilot in the Tekirdag area on joint venture lands acquired from Thrace Basin Natural Gas (Turkiye) Corporation ("TBNG") and Pinnacle Turkey Inc. ("PTI") (Valeura 40%). The well was drilled to a depth of approximately 1,000 metres into the Teslimkoy Formation with a horizontal section of 617 metres and was completed with a 10-stage frac. Over the first 30 days since tie-in, the well has flowed at an average rate of 3.0 MMcf/d through a 34/64" choke. (Note that the initial production rates stated throughout this press release are not necessarily indicative of long term performance or ultimate recovery).

  • Continued to produce and monitor the performance of the first horizontal well DTD-19H in the pilot, which was completed in the less permeable Upper Kesan Formation with seven-stage frac over a shorter lateral length of 425 metres. Over the first 30 days since tie-in, the well flowed at an average rate of 0.4 MMcf/d. The well is continuing to clean up with approximately 63% of the completion load fluid recovered to date.

  • A third horizontal well BTD-5H is expected to spud within the next week targeting the Teslimkoy Formation with a multi-stage frac. A fourth horizontal well is expected to spud in late December 2013 or early January 2014 as the first horizontal well in the Mezardere Formation where success has been achieved with re-entry fracs in existing vertical wells.

  • Completed 10 well re-entry fracs during the July to October 2013 period in the Mezardere Formation slope fan play, increasing the year-to-date total to 12. This program has proved to be very successful at a relatively low cost of approximately $0.5 million per well and has been a major contributor to volume growth since April 2013. The average initial 30-day rate for six wells with 30 days of on-stream history is approximately 0.8 MMcf/d.

  • Progressed our understanding of the upside potential in the Mezardere Formation slope fan play, which potentially includes multiple reservoir targets in channel sands, inter-laminated sands and shales and thicker shale source rock sections. One of the more recent and most successful re-entry fracs was in the Kayi-14 well, which appears to have intersected a high porosity slope channel sand. These results correlate well with the latest 3D seismic attribute mapping in the area, which has identified channel systems within the slope fan lobes that pro-grade to the northeast into the deeper parts of the basin. These results are encouraging from a future prospecting standpoint on the TBNG-PTI joint venture lands and Valeura's Banarli licence.

Thrace Basin - Banarli Exploration Licence (Valeura 100%)

  • Completed the interpretation of new 2D seismic and reprocessed vintage 2D seismic on the 100% owned and operated Banarli Exploration Licence 5104 and identified two potential drilling locations on structural prospects on the new seismic lines. Valeura is continuing to seek a joint venture partner to participate in funding the exploration program on this licence.

Anatolian Basin

  • Applied to the General Directorate of Petroleum Affairs ("GDPA") to relinquish the Bostanci Exploration Licence 4985 (Valeura 100%) and Karakilise Exploration Licence 5052 (Valeura 100%) given higher than expected exploration risk following the new seismic acquisition at Bostanci and the reprocessing of existing seismic at Karakilise, and inability to attract farm-in partners.

  • The Operator of four Gaziantep area exploration licences (Valeura 26%) has applied to the GDPA to relinquish three of these licences, given limited prospectivity. Gaziantep Licence 4607 has been retained at this time, pending further evaluation of the Alibey-1 horizontal well which was drilled in 2012 and has tested small amounts of heavy oil at a high water-cut.

FINANCIAL HIGHLIGHTS

  • Funds flow from operations of $3.1 million in the third quarter of 2013 was up 73% from $1.8 million in the second quarter of 2013 due primarily to higher sales volumes and lower operating costs, partially offset by slightly lower natural gas price realizations in Turkey due to exchange rate fluctuations. Funds flow from operations in the third quarter of 2013 was up 9% from the third quarter of 2012 due to higher Turkish natural gas prices, partially offset by lower sales volumes. (See discussion below regarding non-IFRS measures).

  • Capital expenditures in the third quarter of 2013 of $8.4 million were up 34% from $6.3 million in the second quarter of 2013 reflecting the two-well horizontal drilling program in the Thrace Basin and Bostanci seismic acquisition. Capital expenditures in the third quarter of 2013 were up 50% from the third quarter of 2012 due primarily to increased fracing and seismic activities.

  • Natural gas price realizations in Turkey in the third quarter of 2013 averaged $10.13 per thousand cubic feet ("Mcf"), which were down 2% from the second quarter of 2013 due primarily to a weakening of the Turkish Lira.

  • The corporate average operating netback of $45.07 per boe in the third quarter of 2013 was up 9% from $41.16 per boe in the second quarter of 2013 due primarily to lower unit operating costs in Turkey, partially offset by slightly lower natural gas price realisations. The corporate average netback in the third quarter of 2013 was up 15% from the same period in 2012 due primarily to lower unit operating costs in Turkey, partially offset by slightly lower natural gas price realisations. (See discussion below regarding non-IFRS measures).

  • As at September 30, 2013, the Corporation had a working capital surplus of $9.0 million, including cash and cash equivalents of $9.9 million. This compares to a working capital surplus of $14.7 million as at June 30, 2013.

  • Additional financial and operating results are summarized in the Table 1 below.

Table 1 Financial Results Summary

(thousands of Canadian dollars, except share
 or per share amounts)
Three Months
Ended
September 30,
2013
Three Months
Ended
June 30,
2013
Nine Months
Ended
September 30,
2013
Three Months
Ended
September 30,
2012
Nine Months
Ended
September 30,
2012
Financial
(CDN$ except share and per share amounts)
         
Petroleum and natural gas revenues 5,749 4,897 15,494 5,859 19,533
Funds flow from operations (1) 3,067 1,775 6,429 2,803 9,115
Net loss (4,632) (2,228) (7,678) (702) (3,794)
Capital expenditures 8,445 6,303 21,193 5,643 25,024
Net working capital surplus 9,029 14,735 9,029 13,992 13,992
Cash and cash equivalents 9,850 16,743 9,850 15,578 15,578
Common shares outstanding
     Basic
     Diluted
57,906,135
78,993,352
57,906,135
79,040,602
57,906,135
78,993,352
46,406,135
65,851,102
46,406,135
65,851,102
Share trading
     High
     Low
     Close
0.50
0.31
0.42
0.93
0.40
0.42
1.15
0.31
0.42
1.68
1.20
1.27
2.89
1.18
1.27
Operations          
Production          
     Crude oil & NGLs (bbl/d) 48 48 49 58 63
     Natural Gas (Mcf/d) 5,778 4,882 5,153 6,489 7,718
     BOE/d (@ 6:1) (2) 1,011 862 909 1,140 1,350
Average reference price
        Edmonton light  ($ per bbl)
        AECO ($ per Mcf)
        BOTAS Reference ($ per Mcf) (3)
104.69
2.30
10.63
92.55
3.47
11.21
95.13
3.01
11.05
84.33
2.32
10.07
86.81
2.08
9.58
Average realized price
     Crude oil ($ per bbl)
     Natural gas - Turkey ($ per Mcf)
     Natural gas - consolidated ($ per Mcf)
94.75
10.13
10.03
80.55
10.37
10.24
83.18
10.37
10.22
      78.61
9.27
9.12
80.31
8.71
8.58
Average Operating Netback
($ per BOE @ 6:1) (1) (2)
45.07 41.16 42.13 39.14 37.03

Notes:
(1) The above table includes non-IFRS measures, which may not be comparable to other companies.  Funds flow from operations is calculated as net loss for the period adjusted for non-cash items in the statement of cash flows.  Operating netback is calculated as petroleum and natural gas sales less royalties, production expenses and transportation costs.  See MD&A for further discussion.
(2) BOEs may be misleading, particularly if used in isolation.  A BOE conversion ratio of 6.0 Mcf:1.0 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the well head.
(3) Boru Hatlari ile Petrol Tasima Anonim Sirketi ("BOTAS") owns and operates the national crude oil and natural gas pipeline grids in Turkey.  BOTAS regularly posts prices and its Industrial Interruptible Tariff benchmark is shown herein as a reference price. See the 2012 Annual Information Form for further discussion.

OUTLOOK
To date in 2013 the Corporation has invested approximately $21 million (net) in Turkey and expects to invest up to $26 million (net) for the full year, more than 74% of which is expected to be directed to the TBNG-PTI joint venture lands (Valeura 40%). In the fourth quarter of 2013, the Corporation expects to complete the drilling and fracing of the third horizontal well BTD-5H and to complete up to nine other well-re-entry fracs on the TBNG-PTI joint venture lands (including four already completed in October) from an inventory of more than 30 Mezardere Formation candidates, to be funded from cash flow and existing cash.

The Corporation will continue to seek a joint venture partner for its 100% owned and operated Banarli Exploration Licence 5104. Under the terms for this 185 square mile exploration licence awarded to Valeura in April 2013, an initial well must be spudded by late March 2014.

The 2014 work program and capital budget is currently under development with partners.

ABOUT THE CORPORATION
Valeura Energy Inc. is a Canada-based public company currently engaged in the exploration, development and production of petroleum and natural gas in Turkey and Western Canada.

OIL AND GAS ADVISORIES
When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs, or 6,000 cubic feet of natural gas. Barrel of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of 6.0 Mcf:1.0 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.

The initial production rates for wells stated herein are not necessarily indicative of long term performance or ultimate recovery. To date, shallow gas conventional wells and frac'd unconventional tight gas wells have exhibited relatively high decline rates at more than 50% and 75%, respectively, in their first year of production.

ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION
This news release contains certain forward-looking statements including, but not limited to: projected 2013 capital spending; the potential number of wells to be drilled and the ability to finance development; anticipated work programs, budgets and operational plans, including targeted seismic, drilling, completions, workovers, well re-entry fracs and fracs on new wells and the continued drilling of horizontal wells with multi-stage frac completions, and the expected impact and timing thereof; the future development program in the Thrace Basin; the potential for re-completions and a follow-on development program in the Mezardere Formation, and the number of re-completion candidates; the timing, costs and ability to fund each of the foregoing; and, the plans for and prospectivity of the Banarli Licence 5104 and other licences. Forward-looking information typically contains statements with words such as "anticipate", "estimate", "expect", "target", "potential", "could", "should", "would" or similar words suggesting future outcomes. The Corporation cautions readers and prospective investors in the Corporation's securities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Corporation.

Forward looking information is based on management's current expectations and assumptions regarding, among other things: continued political stability of the areas in which the Corporation is operating and completing transactions; continued operations of and approvals forthcoming from the GDPA in a manner consistent with past conduct; results of future seismic programs; future drilling, fracing and re-completion activity, including the extent and pace of tight gas delineation and development drilling in the Tekirdag area and the funding thereof; the ability to manage water production; future production rates and associated cash flow; future capital and other expenditures (including the amount and nature thereof); the ability to meet drilling deadlines and other requirements under licences and leases, including spudding deadlines under the Banarli Licence 5104 and Copkoy Licence 5147; the ability to attract partners and negotiate farm-in arrangements; future sources of funding; future economic conditions; future currency and exchange rates; and, the Corporation's continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, budgets are based upon the Corporation's current work programs proposed by partners and associated exploration plans and anticipated costs, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of fracing and other specialized oilfield equipment and service providers, and unexpected delays and changes in market conditions. Although the Corporation believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

Forward-looking information involves significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a significant degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Corporation including, but not limited to: risks associated with the oil and gas industry (e.g. operational risks in exploration, inherent uncertainties in interpreting geological data, and changes in plans with respect to exploration or capital expenditures, the uncertainty of estimates and projections in relation to costs and expenses, and health, safety, and environmental risks); uncertainty regarding the sustainability of initial production rates and decline rates thereafter; uncertainty regarding the ability to address technical drilling challenges and manage water production; uncertainty regarding the state of capital markets and the availability of future financings; the risk of being unable to meet drilling deadlines and the requirements under licences and leases (including Banarli Licence 5104 and Copkoy Licence 5147); the ability to attract partners and negotiate farm-in arrangements; future sources of funding; uncertainty regarding the manner in which the new Turkish Petroleum Law and associated regulations will be implemented; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues, terrorist attacks, insurgencies or civil unrest (particularly in the southeastern part of Turkey); the risks of increased costs and delays in timing related to protecting the safety and security of Valeura's personnel and property; the risk of commodity and BOTAS pricing and foreign exchange rate fluctuations; the uncertainty associated with negotiating with third parties in countries other than Canada; the risk of partners having different views on work programs and potential disputes among partners and service providers; the uncertainty regarding government and other approvals; potential changes in laws and regulations; risks associated with weather delays and natural disasters; and, the risk associated with international activity. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.  See Valeura's 2012 Annual Information Form for a detailed discussion of the risk factors.

Additional information relating to Valeura is also available on SEDAR at www.sedar.com

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

 

SOURCE: Valeura Energy Inc.

For further information:


Jim McFarland, President and CEO
Valeura Energy Inc.
(403) 930-1150
jmcfarland@valeuraenergy.com

Steve Bjornson, CFO
Valeura Energy Inc.
(403) 930-1151
sbjornson@valeuraenergy.com

www.valeuraenergy.com

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