Valeura announces new strategy for its 100% Banarli licence in Turkey and third quarter 2014 financial and operating results

CALGARY, Nov. 12, 2014 /CNW/ - Valeura Energy Inc. ("Valeura" or the "Corporation") (TSX: VLE) is pleased to announce a new strategy for its 100% owned and operated Banarli licence in the Thrace Basin of Turkey and to report highlights of its unaudited financial and operating results for the three and nine month periods ended September 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.

"As we announced on October 7, three new conventional natural gas discoveries in the Osmanli area on the TBNG JV lands promise a significant boost to production in Turkey", said Jim McFarland, President and Chief Executive Officer. "The largest discovery was in the Gurgen-1 well, which has been on production for six days and has produced at an average restricted rate of 3.1 MMcf/d (gross) on a 18/64 inch choke at an average flowing tubing pressure of 1,560 psi. The two other discoveries tested in aggregate 3.5 MMcf/d (gross) and should also be on-stream by the end of November. In addition, two other wells in this Osmanli program finished drilling in October and are cased and awaiting completion of testing and tie-in. The drilling rig is currently drilling a shallow well for a third party in the Thrace Basin but is expected to return in late November to spud at least one additional follow-up well on the Gurgen structure."

"We are also excited to advise that these most recent Osmanli results have been decisive in building our confidence to shape a new strategy for our 100% owned and operated Banarli licence, which we want to advance as quickly as possible in 2015. The initial 2015 program is expected to cost approximately US$6.0 million, including up to 140 square kilometres of new 3D seismic and at least one exploration commitment well targeting the Osmancik and Mezardere formations at a depth of approximately 2,500 metres," said McFarland. "We have identified more than 15 leads on the existing 2D seismic and expect that the 3D seismic will enable us to mature and high grade a number of these leads to drillable prospects and also expand the lead and prospect inventory on both shallow and deep targets on Banarli. We are also pursuing options to accelerate and expand the Banarli program, including the ongoing effort to attract a farm-in partner to explore the deeper horizons only, while we pursue the shallower horizons on a 100% basis."

Q3 2014 RESULTS AT A GLANCE ⁽¹⁾

• Drilled three new conventional gas discoveries
• Net sales 997 boe/d
• Funds flow from operations $3.0 million
• Working capital surplus $9.9 million
• Natural gas price realizations $9.66 per Mcf
• Natural gas reference prices in Turkey (priced in Turkish Lira) increased by 9% effective October 1
• Operating netback $43.85 per boe
• Net capital expenditures $2.5 million
• Spudded five exploration and development wells
• Completed two re-entry fracs and six recompletion workovers
• Completed sale of Canadian assets

(1)

Continuing operations in Turkey only. See below for definitions, non-IFRS measures and other advisories.

OPERATIONAL HIGHLIGHTS

• Net petroleum and natural gas sales in Turkey in the third quarter of 2014 averaged 997 barrels of oil equivalent per day ("boe/d"), including 5.9 million cubic feet per day ("MMcf/d") of natural gas and 7 barrels of oil per day, which were 3% higher than the third quarter of 2013. Net petroleum and natural gas sales in the first nine months of 2014 averaged 1,131 boe/d, which was up 32% from the same period in 2013.
  
  
• Net capital expenditures of $2.5 million in the third quarter and $8.5 million in the first nine months of 2014 are down 69% and 60%, respectively, from same periods in 2013. This reflects the current focus on the more cost effective exploration and development program in the Thrace Basin and our strategy to deliver production growth while funding capital expenditures from cash flow and cash on hand only.
  
  
• The Turkish government announced a 9% increase in domestic natural gas prices, which are priced in Turkish Lira ("TL"), effective October 1, 2014. The Corporation expects this increase to flow through to all of its natural gas sales contracts and increase its average natural gas price realizations in Turkey from $9.66 per thousand cubic feet ("Mcf") in the third quarter to approximately $10.20 per Mcf in the fourth quarter at the current exchange rate of 2.0 TL/Cdn$.

Thrace Basin - TBNG JV (Valeura 40%)

• Discovered natural gas in three new exploration wells drilled and completed in the third quarter on joint venture lands acquired from Thrace Basin Natural Gas (Turkiye) Corporation ("TBNG") and Pinnacle Turkey Inc. ("PTI") (the "TBNG JV") (Valeura 40%), as disclosed on October 7, 2014. The wells Gurgen-1, Tavanli-1 and Biyikali-2 were drilled on new 3D seismic acquired in late 2013 in the Osmanli area located just south of Valeura's 100% Banarli exploration licence. The three wells tested 7.5 MMcf/d (gross), in aggregate, on short term flow tests.
  
  
• Subsequent to the end of the third quarter, two additional wells were drilled and cased in the Osmanli area, including Guney Osmanli-3 and Dogu Osmanli-1.

Gurgen-1

• The Gurgen-1 exploration well was drilled and cased to a depth of 2,100 metres into the Osmancik formation and was tested at an initial rate of 4.0 MMcf/d (gross). The cost to drill, complete and tie-in the well was approximately US$1.2 million (gross). The well was tied-in to the closest sales line with a 3.5 kilometre, six inch lateral and was put on-stream on November 5. The line was sized to handle additional wells on the Gurgen structure.
  
  
• The well has been on production for six days and has produced at an average restricted rate of 3.1 MMcf/d (gross) on a 18/64 inch choke at an average flowing tubing pressure of 1,560 pounds per square inch ("psi").
  
  
• At least one follow-up well is expected to spud on the Gurgen structure before the end of November and be completed before year-end.

Tavanli-1

• The Tavanli-1 exploration well was drilled and cased to a depth of 1,300 metres into the Osmancik formation and was tested at an initial rate of 2.0 MMcf/d (gross). The estimated final cost to drill, complete and tie-in the well is approximately US$0.8 million (gross). The well is being tied-in to the gathering system with a 1.8 kilometre lateral and is expected to be on-stream by the end of November.

Biyikali-2 Sidetrack

• The Byikali-2 sidetrack exploration well was drilled and cased to a depth of 900 metres into the Osmancik formation and was tested at an initial rate of 1.5 MMcf/d (gross). The estimated final cost to drill, complete and tie-in the well is approximately US$0.7 million (gross). The well is being tied-in to the gathering system with a 2.9 kilometre lateral and is expected to be on-stream by the end of November.

Guney Osmanli-3

• The Guney Osmanli-3 development well was drilled and cased to a depth of 1,080 metres into the Osmancik formation and was tested at an initial rate of 0.5 MMcf/d (gross). The estimated cost to drill, complete and tie-in the well with a 0.5 kilometre lateral is approximately US$0.8 million (gross). The well is expected to be tied-in to the gathering system in December.

Dogu Osmanli-1

• The Dogu Osmanli-1 exploration well was spudded on October 16 and was drilled by the TBNG JV partners to a depth of 2,100 metres into the Mezardere formation at a cost of approximately US$0.8 million (gross). Log analysis indicated gas bearing pay in the Mezardere formation only. Valeura elected to case the well as an independent operation and plans to proceed with a strategically important completion and test of the Mezardere formation in late November. The estimated cost of the independent operation to case, complete and test the well is approximately US$0.3 million (Valeura 100%). If the test confirms commercial rates, it is expected that Valeura will work with TransAtlantic Petroleum Ltd., the operator of the TBNG JV, to tie-in the well into the TBNG JV facilities.
  
  (Note that the initial test rates stated in this press release for the three new discovery wells and the new development well may not be indicative of stabilized on-stream production rates).

Other Programs

• Drilled and fracked the TDR-5H horizontal well. The well was drilled at a record pace of 12 days to a vertical depth of 992 metres into the Teslimkoy formation with a horizontal section of 569 metres and was completed with an 8-stage frac. The cost to drill, complete, frac and tie-in the well was approximately US$2.45 million (gross). The well is tied-in to the gathering system and over the initial 30 days following tie-in, flowed at an average rate of 1.3 MMcf/d (gross) ("IP30").
  
  
• Completed two well re-entry fracs in the Teslimkoy formation at the DTD-7 and DTD-11 wells. The average per well IP30 rate was approximately 0.5 MMcf/d.
  
  
• An additional six shallow gas recompletion workovers were also carried out in the quarter.
  
  (Note that the initial on-stream production rates ("IP30") stated throughout this press release are not necessarily indicative of long term performance or ultimate recovery and are subject to decline rates stated below).

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 exploration licence 5104 to the new licencing regime adopted by the Turkish government in May 2013. Valeura expects this process to continue to successfully unfold, with the conversion of the Banarli exploration licence potentially achievable by early in the first quarter of 2015, if not sooner. 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).

FINANCIAL HIGHLIGHTS

• The financial results summarized below and in Table 1 are for continuing operations in Turkey only and prior period figures have been reclassified under IFRS to exclude discontinued operations in Canada, which were sold on August 19, 2014.
  
  
• Funds flow from operations of $3.0 million in the third quarter of 2014 was down 8% from the second quarter of 2014 reflecting lower sales volumes and lower natural gas price realizations in Turkey due to some weakening of the TL, which is the pricing basis for Turkish gas sales, partially offset by lower general and administrative costs. Funds flow from operations in the third quarter of 2014 was up 2% from the same period in 2013 due primarily higher sales volumes and lower general and administrative costs, partially offset by lower natural gas price realizations in Turkey due to weakening of the TL. (See discussion below regarding non-IFRS measures).
  
  
• Net capital expenditures of $2.5 million in the third quarter of 2014 were up 60% from the second quarter of 2014 due to higher drilling expenditures and down 69% from the same period in 2013 due to lower drilling and fracking expenditures.
  
  
• Total general and administrative expenses in the third quarter of 2014 were down 7% from the second quarter of 2014 and down 12% from the same period in 2013 due to overall lower office expenses, business development costs and travel costs.
  
  
• The average natural gas price realization in Turkey of $9.66 per Mcf in the third quarter of 2014 was down 3% from the second quarter of 2014 and down 5% from the same period in 2013 reflecting fluctuations in the exchange rate for the TL.
  
  
• The average operating netback in Turkey of $43.85 per boe in the third quarter of 2014 was down 2% from the second quarter of 2014 due primarily to lower natural gas price realizations in Turkey, partially offset by lower unit operating costs, and down 4% from the same period in 2013 due primarily to lower natural gas price realizations, partially offset by lower unit operating costs. (See discussion below regarding non-IFRS measures).
  
  
• As at September 30, 2014, the Corporation had a working capital surplus of $9.9 million, including cash and cash equivalents of $6.0 million. This working capital surplus is 11% higher than at June 30, 2014 and 9% higher than at September 30, 2013.
  
  
• Additional financial and operating results are summarized in the Table 1 below.

Table 2 Financial Results Summary ⁽¹⁾

(thousands of Canadian dollars, except share or per share amounts)		Three Months Ended September 30, 2014	Three Months Ended June 30, 2014	Nine Months Ended September 30, 2014	Three Months Ended September 30, 2013	Nine Months Ended September 30, 2013
Financial (CDN$ except share and per share amounts)
Petroleum and natural gas revenues		5,330	6,097	18,077	5,466	14,737
Funds flow from operations ^(2)		3,011	3,283	9,932	2,940	6,192
Net income (loss)		(171)	285	393	(4,711)	(7,717)
Capital expenditures (net)		2,515	1,568	8,455	8,024	21,143
Net working capital surplus		9,865	8,866	9,865	9,029	9,029
Cash and cash equivalents		5,974	5,608	5,974	9,850	9,850
Common shares outstanding
	Basic	57,906,135	57,906,135	57,906,135	57,906,135	57,906,135
	Diluted	77,146,102	77,406,352	77,146,102	78,993,352	78,993,352
Share trading
	High	0.57	0.70	0.78	0.50	1.15
	Low	0.33	0.50	0.30	0.31	0.31
	Close	0.33	0.55	0.33	0.42	0.42
Operations
Production
	Crude oil (bbl/d)	7	8	7	16	17
	Natural Gas (Mcf/d)	5,943	6,693	6,741	5,708	5,050
	BOE/d (@ 6:1) ^(3)	997	1,123	1,131	967	859
Average reference price
	BOTAS Reference ($ per Mcf) ^(4)	10.14	10.40	10.18	10.63	11.05
Average realized price
	Crude oil ($ per bbl)	82.18	88.25	82.26	99.26	97.28
	Natural gas ($ per Mcf)	9.66	9.91	9.73	10.13	10.37
Average Operating Netback ($ per BOE @ 6:1) ^(2) (3)		43.85	44.95	44.57	45.69	43.57

Notes:
(1)	The above table includes figures from continuing operations in Turkey only.  Prior period figures have been reclassified to remove discontinued operations in Canada.  See MD&A for further discussion on discontinued operations.
(2)	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.
(3)	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.
(4)	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 Annual Information Form for further discussion.

OUTLOOK

New Banarli Strategy

Valeura has developed a new strategy for the 100% owned and operated Banarli licence in the Thrace Basin to explore the Osmancik and Mezardere formations down to a depth of approximately 2,500 metres, commencing in 2015. The Banarli licence covers an area of 480 square kilometres (185 square miles or 185 sections). This new strategy is primarily driven by the recent success of the Osmanli area exploration drilling program on new 3D seismic on the TBNG JV lands immediately south of the Banarli licence. The Osmanli program reinforced the value of 3D seismic in exploring for traps along the extensive fault systems in the Thrace Basin, including the ability to image trap types that had not been pursued in the past on the TBNG JV lands.

Having regard to the value of 3D seismic and the improved cash position of the Corporation, Valeura has developed a preliminary work program and budget for 2015 at Banarli that includes approximately 140 square kilometres of new 3D seismic as a first step in the planned exploration program, which will complement the existing 2D seismic coverage of more than 300 kilometres on the licence, including 92 kilometres of new 2D seismic shot by Valeura in 2013. Estimated costs to acquire, process and interpret such a seismic program are approximately US$4.0 million based on the recent experience at Osmanli.

The preliminary 2015 work program also includes the drilling of at least one commitment exploration well in the third or fourth quarter under the assumption that a number of independent drillable prospects will be matured and high graded from more than 15 leads that have been mapped on the 2D seismic. The costs to drill, complete and test a 2,500 metre well is estimated to be approximately US$1.9 million. This drilling program could be expanded in late 2015, depending on the Corporation's cash position at the time.

Valeura continues to believe that there is also significant upside potential for a basin-centred gas play in the deeper horizons at Banarli below about 3,000 metres. At this depth and associated temperature, the source rock shales and reservoir sands could be in an active hydrocarbon-generating "kitchen" forming a basin-centered gas accumulation, with regionally pervasive, low permeability, gas-saturated sandstone reservoirs exhibiting abnormally high pressures. The Corporation has an active process underway to seek a joint venture partner to participate in funding such a potential high impact deep exploration program and a number of companies remain engaged in this process. However, based on the recent exploration success in the adjacent Osmanli area and its new strategy for Banarli, the Corporation now intends to exploit the shallow and medium depth horizons on a 100% basis and is seeking a farm-out partner for the deeper horizons only. The Corporation expects that the 3D seismic to be shot in 2015 will also prove to be valuable asset in this farm-out strategy.

Capital Expenditure Outlook

The Corporation expects to complete a final net capital expenditure program in Turkey of approximately $11 to 12 million (net) in 2014, focused almost entirely on natural gas development on the TBNG JV lands.

The final work program on the TBNG JV lands in 2014 is expected to include nine to 10 wells (gross) including three horizontal wells and four vertical wells spudded in the first nine months of the year and two to three vertical wells in the fourth quarter, of which one is already drilled and completed. This includes one or two follow-up wells (gross) on the Gurgen structure.

Six well re-entry fracs (gross) were completed in the first nine months of 2014, which completes the program for year. Up to 21 recompletion workovers (gross) in shallow gas formations are also expected to be completed in 2014, of which 18 had been completed in the first nine months of the year.

Joint venture technical and operating committee meetings are planned for December 2014 to develop the planned work program and budget for the TBNG JV, Edirne and Gaziantep assets in Turkey in 2015.

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.

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.

The initial test rates stated herein are preliminary in nature and may not be indicative of stabilized on-stream production rates. Also, the initial on-stream production rates for wells stated herein are not necessarily indicative of long term performance or ultimate recovery. To date, shallow gas conventional wells and fracked 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: future price realizations in Turkey; the planned fourth quarter 2014 drilling program and well tie-ins for the  shallow gas development programs in the Thrace Basin; follow-on well locations on the Gurgen structure; the extent of exploration leads on the Banarli licence; the corporate 2014 work program and budget outlook, operational plans and costs (drilling, fracking and workovers) for the tight gas and conventional shallow gas development programs on the TBNG JV lands in Thrace Basin; the preliminary 2015 work program and budget for the 100% owned Banarli licence; the possible expansion of the drilling program in 2015 on the Banarli licence and the associated cost; the availability of operating cash flow and the ability to finance development; the planned drilling of horizontal and vertical wells, well re-entry fracs and well recompletion workovers and the expected impact thereof; tieing-in the new wells and getting these on-stream; 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; and, the ability to convert the Banarli licence 5104 under the new licencing regime in Turkey. 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 and follow-on drilling locations; the prospectivity of the Banarli licence; 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 for deep exploration on the Banarli licence 5104; 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, 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; 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; 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