Valeura announces second quarter 2014 financial and operating results

CALGARY, Aug. 13, 2014 /CNW/ - Valeura Energy Inc. ("Valeura" or the "Corporation") (TSX: VLE) is pleased to report highlights of its unaudited financial and operating results for the three and six month periods ended June 30, 2014 and 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 ("MD&A"), has been filed on SEDAR at www.sedar.com and posted on the Corporation's website at www.valeuraenergy.com.

"We have remained disciplined in executing our current strategy of delivering production growth while living within our means and funding capital expenditures from cash flow and cash on hand," said Jim McFarland, President and Chief Executive Officer. ''Net sales grew by 45% in the first half of 2014 compared to the same period in 2013, while funds flow from operations of $7.2 million in the first half of 2014 was more than sufficient to fund capital expenditures of $5.4 million. Capital expenditures are expected to increase in the second half of 2014 due to a planned ramp-up in drilling in Turkey. Full year capital expenditures are expected to be in the range of $14 to 16 million and yield a 10 to 16% growth in annual production in Turkey compared to 2013."

"The focus on operational and capital efficiency continues to bear fruit," said McFarland. "Corporate unit operating costs have been approximately halved in the past year and averaged $7.11 per boe in the second quarter of 2014. This improvement was instrumental in growing corporate operating netbacks by 9% to $44.70 per boe in the second quarter of 2014 compared to the same period in 2013, more than offsetting a 4% decline in averaged realized prices. Significant progress has also been made in reducing drilling times and associated costs in Turkey and we are targeting to realize further capital cost reductions of 10 to 20% in the current round of drilling."

Q2 2014 RESULTS AT A GLANCE

• Net sales 1,166 boe/d, up 35% from Q2 2013
  
  
• Funds flow from operations $3.4 million, up 93% from Q2 2013
  
  
• Corporate operating netback $44.70 per boe, up 9% from Q2 2013
  
  
• Corporate unit operating costs $7.11 per boe, down 46% from Q2 2013
  
  
• Net capex $1.5 million
  
  
• Completed four re-entry fracs and seven recompletion workovers
  
  
• Completed interpretation of new Osmanli 3D seismic survey and firmed-up a continuous multi-well drilling program for the second half of 2014 aimed at improved operational efficiency and lower costs
  
  
• Re-started drilling program in Turkey on July 28 and drilled the sixth horizontal well TDR-5H into the Teslimkoy Formation in 12 days at a record rate of penetration; 8-stage frac planned

(See below for definitions, non-IFRS measures and other advisories)

OPERATIONAL HIGHLIGHTS

• Net corporate petroleum and natural gas sales in the second quarter of 2014 averaged 1,166 barrels of oil equivalent per day ("boe/d"), which was 35% higher than sales in second quarter of 2013. Net sales in Turkey in the second quarter of 2014 averaged 1,123 boe/d, including 6.7 million cubic feet per day ("MMcf/d") of natural gas and 8.0 barrels of oil per day. Net sales in Canada in the second quarter of 2014 averaged 43 boe/d.
  
  
• Net corporate petroleum and natural gas sales in the first six months of 2014 averaged 1,241 boe/d, which was up 45% from the same period in 2013.
  
  
• Capex was reduced in the second quarter of 2014 consistent with the plan announced in May to pause the drilling program in the Thrace Basin to provide time to interpret the new Osmanli 3D seismic and to develop a program of firm, independent locations, which could be drilled back-to-back for the current phase of drilling that began on July 28. This strategy is expected to deliver improved operational efficiency and an improvement of 10 to 20% in costs for the drilling and completion program.

Thrace Basin – TBNG JV (Valeura 40%)

• Completed four re-entry fracs, including two in the Osmancik formation (Kazanci-5 and TB-13) and two in the Mezardere formation (BTD-1 and Kayi-16) and seven shallow gas recompletion workovers, during the second quarter on joint venture lands acquired from Thrace Basin Natural Gas (Turkiye) Corporation ("TBNG") and Pinnacle Turkey Inc. ("PTI") (the "TBNG JV") (Valeura 40%).
  
  
• Completed the interpretation of the new 232 square kilometre 3D seismic survey in the Osmanli area on the TBNG JV lands and identified four firm exploration locations and a re-entry sidetrack opportunity on new prospects in the Osmancik formation at depths of approximately 1,400 metres. Drilling of certain of these prospects is expected to follow rig release from the TDR-5H well.
  
  
• Spudded the sixth horizontal well TDR-5H on the TBNG JV lands on July 28, which was drilled in 12 days to a vertical depth of 992 metres into the Teslimkoy formation with a horizontal section of 569 metres. The well achieved a record rate of penetration for the horizontal wells drilled to date. It is expected that the well will be completed by the end of August with an 8-stage frac.

Thrace Basin – Banarli Licence (Valeura 100%)

• The Corporation continued to make progress with the General Directorate of Petroleum Affairs ("GDPA") and offsetting licence holders to convert the 100% owned and operated Banarli licence 5104 to the new licencing regime adopted by the Turkish government in May 2013. Voluntary conversion of existing licences to the new regime is encouraged, where possible, and would require re-alignment of the licence boundaries and negotiation with offset licence holders to fit a new grid system. Agreements have been reached with the offset licence holders TBNG JV and Turkiye Petrolleri Anonim Ortakligi ("TPAO") to facilitate the conversion and the GDPA has been so advised. If such a conversion is approved by the GDPA, the immediate effect would be to lengthen the initial term of the licence to five years and re-start the clock on the drilling commitment timing, thereby delaying the required spud date to late 2014 or early 2015, depending on the timing of approval of the conversion. There is no certainty that such a conversion can be achieved and timing remains uncertain. (See the Corporation's 2013 AIF for a detailed description of the old and new licencing terms in Turkey).
  
  
• Given the continued uncertainty associated with converting the Banarli licence to the new licencing regime, the Corporation is planning to spud a licence-retention exploration well in the fourth quarter of 2014 under the current licencing terms, targeting the Osmancik Formation at a depth of approximately 2,000 metres. The planned location is near the southern boundary of the Banarli licence, which is contiguous with the TBNG JV lands. The cost to drill and complete such a well is expected to be approximately US$1.2 million (net) and is included in the Corporation's budget for 2014.
  
  
• Valeura is continuing to seek a joint venture partner to participate in funding a deep exploration drilling program on the Banarli licence, targeting a potential basin-centered gas play below 3,000 metres. The Corporation has engaged Moyes & Co., an internationally active acquisition and divestment firm, to assist in the farm-out process.

FINANCIAL HIGHLIGHTS

• Funds flow from operations of $3.4 million in the second quarter of 2014 was down 8% from the first quarter of 2014 reflecting lower sales volumes, partially offset by slightly higher natural gas price realizations in Turkey due to some strengthening of the Turkish Lira ("TL"), which is the pricing basis for Turkish gas sales. Funds flow from operations in the second quarter of 2014 was up 93% from the same period in 2013 due primarily to higher sales volumes, lower operating costs and lower general and administrative expenditures, partially offset by lower natural gas price realizations in Turkey due to weakening of the TL. (See discussion below regarding non-IFRS measures).
  
  
• Capital expenditures of $1.5 million in the second quarter of 2014 were down 62% from the first quarter of 2014 and down 76% from the same period in 2013 due to lower drilling and fracking expenditures.
  
  
• Total general and administrative expenses in the second quarter of 2014 were down 17% from the first quarter of 2014 and down 24% from the same period in 2013 due to overall lower office expenses, employee bonus payments, business development costs and travel costs.
  
  
• The average natural gas price realization in Turkey of $9.91 per thousand cubic feet ("Mcf") in the second quarter of 2014 was up 3% from the first quarter of 2014 and down 4% from the same period in 2013 reflecting fluctuations in the exchange rate for the TL.
  
  
• The corporate average operating netback of $44.70 per boe in the second quarter of 2014 was up 1% from the first quarter of 2014 due primarily to higher natural gas price realizations in Turkey, partially offset by higher unit operating costs and royalties (reflecting lower volumes), and up 9% from the same period in 2013 due primarily to lower unit operating costs, partially offset by lower natural gas price realizations. (See discussion below regarding non-IFRS measures).
  
  
• As at June 30, 2014, the Corporation had a working capital surplus of $8.9 million, including cash and cash equivalents of $5.6 million. This working capital surplus is 30% higher than the surplus at March 31, 2014 due primarily to lower capital expenditures in the second quarter.
  
  
• 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 June 30, 2014	Three Months Ended March 31, 2014	Six Months Ended June 30, 2014	Three Months Ended June 30, 2013	Six Months Ended June 30, 2013
Financial (CDN$ except share and per share amounts)
Petroleum and natural gas revenues		6,359	6,896	13,255	4,897	9,745
Funds flow from operations ^(1)		3,433	3,744	7,177	1,775	3,362
Net income (loss)		462	330	792	(2,228)	(3,046)
Capital expenditures		1,504	3,946	5,450	6,303	12,748
Net working capital surplus		8,866	6,817	8,866	14,735	14,735
Cash and cash equivalents		5,608	5,484	5,608	16,743	16,743
Common shares outstanding
	Basic	57,906,135	57,906,135	57,906,135	57,906,135	57,906,135
	Diluted	77,406,352	77,406,352	77,406,352	79,040,602	79,040,602
Share trading
	High	0.70	0.78	0.78	0.93	1.15
	Low	0.50	0.30	0.30	0.40	0.40
	Close	0.55	0.64	0.55	0.42	0.42
Operations
Sales
	Crude oil & NGLs (bbl/d)	37	38	38	48	51
	Natural Gas (Mcf/d)	6,775	7,675	7,223	4,882	4,835
	BOE/d (@ 6:1) ^(2)	1,166	1,317	1,241	862	856
Average reference price
	Edmonton light ($ per bbl)	104.51	99.74	102.12	92.55	90.36
	AECO ($ per Mcf)	4.68	4.76	4.72	3.47	3.37
	BOTAS Reference ($ per Mcf) ^(3)	10.40	10.02	10.21	11.21	11.29
Average realized price
	Crude oil ($ per bbl)	87.98	78.95	83.53	80.55	77.54
	Natural gas - Turkey ($ per Mcf)	9.91	9.64	9.77	10.37	10.51
	Natural gas - consolidated ($ per Mcf)	9.84	9.60	9.71	10.24	10.33
Average Operating Netback ($ per BOE @ 6:1) ^(1) (2)		44.70	44.26	44.47	41.16	40.35

	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 2013 AIF for further discussion.

OUTLOOK

The Corporation expects to execute a capital expenditure program and budget of up to $14 to $16 million (net) in Turkey in 2014, including up to $9 to $11 million in the second half of 2014, focused on natural gas development in the Thrace Basin, and contingent on the level of operating cash flow. This total capital expenditure outlook for 2014 is back-end loaded reflecting the majority of the drilling in the second half of 2014. After drilling two wells in the first quarter of 2014 and pausing for just under five months to firm-up the drilling inventory to facilitate a continuous, more cost effective drilling and completions program on the TBNG JV lands, drilling re-started on July 28.

The planned work program on the TBNG JV lands in 2014 is currently expected to include up to 11 horizontal and vertical wells (gross) utilizing a single drilling rig, including seven firm and four contingent locations. Of this total, up to five horizontal wells with multi-stage frac completions are planned targeting tight gas reservoirs in the Mezardere and Teslimkoy Formations and up to six vertical wells are planned targeting conventional gas reservoirs in the Osmanli area on new 3D seismic. The average projected cost to drill and frac the upcoming horizontal wells is approximately US$2.5 million per well (gross). The average cost to drill and complete the conventional vertical wells in the Osmanli area is approximately US$1.0 million per well (gross).

Up to eight well re-entry fracs (gross) are also planned in 2014, primarily targeting the Mezardere Formation, and up to 18 recompletion workovers (gross) in shallow gas formations.

To the end of the second quarter of 2014, the Corporation had completed two horizontal wells BTD-2H and TDR-11H, fracs on four new wells (including the BTD-2H and TDR-11H wells and two vertical wells drilled in 2013), four re-entry fracs and 12 recompletion workovers. Subsequent to the end of the second quarter, the horizontal well TDR-5H was spudded on July 28. Upon rig release from the TDR-5H well, the drilling rig is expected to move to the first of the Osmanli area exploration wells.

The Corporation will continue to seek a joint venture partner to participate in funding a deep exploration drilling program on the Banarli licence, targeting a potential basin-centered gas play below 3,000 metres. The potential conversion of the Banarli licence to the new licensing regime in Turkey may facilitate this process.

The Corporation is also actively pursuing the sale of the small, non-strategic assets in Canada. A small property at Carmangay was sold in the second quarter of 2014 and the Corporation is targeting the sale of the remaining assets later in 2014.

The Corporation now expects 2014 corporate production volumes to average 1,050 to 1,100 boe/d, approximately seven to 12% higher than the average production in 2013, reflecting a shift in the majority of the drilling in Turkey to the second half of 2014 and the potential sale of all of the Canadian assets. Production volumes in Turkey in 2014 are expected to average 1,030 to 1,080 boe/d, approximately 10 to 16 percent higher than the average production in Turkey in 2013.

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 natural gas liquids, 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.

ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION

This news release contains certain forward-looking statements including, but not limited to: the 2014 work program and budget outlook, operational plans and costs (drilling, fracking and workovers) for the tight gas and conventional shallow gas development programs in the Thrace Basin; the availability of operating cash flow and the ability to finance development; estimated cost reductions and the extent thereof; the planned drilling of horizontal and vertical wells, well re-entry fracs and well recompletion workovers and the expected impact thereof; the timing, estimated costs and ability to fund each of the foregoing; the plans to attract a joint venture partner to drill the deep, potential basin-centered gas play on the Banarli licence 5104; the potential plans to drill an exploration well on the Banarli licence 5104 under the current licencing terms, and the costs and timing thereof; the ability to convert the Banarli licence 5104 under the new licencing regime in Turkey and thereby defer the drilling commitment timing to hold the licence; the potential sale of all of the Canadian assets in 2014; and the 2014 production volume outlook. 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; future drilling, fracking and recompletion activity, including the extent and pace of tight gas delineation and development drilling in the Tekirdag area and the funding thereof; the prospectivity of the Osmanli area on the TBNG JV lands; the ability to manage water production; future production rates, capital efficiencies and associated cash flow; cost reductions; 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 the spudding deadline under the Banarli licence 5104; the ability to attract partners and negotiate farm-in arrangements, in particular on the Banarli licence 5104; future sources of funding; the ability to sell all of the Canadian assets in 2014; 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, the Corporation's 2014 work program and budget are based upon the current work programs proposed by partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of fracking 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 secure farm-in partners; the risk of being unable to meet drilling deadlines and the requirements under licences and leases (including the Banarli licence 5104); uncertainty regarding converting licenses under the GDPA's new licensing regime and negotiations with other licence holders; uncertainty regarding the amount of operating cash flow; 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; uncertainty regarding future cost reductions and the extent thereof; 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 fluctuations in commodity pricing and BOTAS pricing (in TL); the risk of fluctuations in foreign exchange rates, particularly the TL, which has weakened in the past year; 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 the Corporation's Annual Information Form for the year ended December 31, 2013 ("2013 AIF") 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.

Jim McFarland, President and CEO, Valeura Energy Inc., [phone], [email protected]; Steve Bjornson, CFO, Valeura Energy Inc., [phone], [email protected], www.valeuraenergy.com