Valeura Announces Strong Fourth Quarter 2014 Financial and Operating Results and Increased Year-End 2014 Reserves

CALGARY, March 10, 2015 /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 month period ended December 31, 2014, audited results for the year ended December 31, 2014, year-end 2014 reserves and an update on subsequent developments. The complete quarterly reporting package for the Corporation, including the audited annual financial statements and associated management's discussion and analysis ("MD&A") and the 2014 annual information form ("2014 AIF"), have been filed on SEDAR at www.sedar.com and posted on the Corporation's website at www.valeuraenergy.com.

"Valeura recorded strong results in the fourth quarter, realizing record high average natural gas sales prices and operating netbacks in Turkey of $10.62 per Mcf and $46.22 per boe, respectively, and delivering $3.7 million in funds flow from operations", said Jim McFarland, President and Chief Executive Officer. "Net sales in the fourth quarter were up 18% from the third quarter, boosted by production from five new conventional natural gas wells in the Osmanli area that were tied-in during the quarter.

"Year-end 2014 reserves also continued to grow. We replaced 121% of 2014 production with proved reserves additions and 214% with proved plus probable reserves additions, increasing proved reserves ("1P") by 5% to 1.7 million boe and proved plus probable reserves ("2P") by 9% to 5.8 million boe.

"Looking forward, 2015 promises be an exciting year for Valeura as we transition to an operator in the Thrace Basin and ramp up activity on the 100% owned Banarli licence, commencing with the planned 3D seismic acquisition in the second quarter and expected drilling of at least one licence retention well in the fourth quarter.  We are in a fortunate position and expect to be able to fund the Banarli program from cash on hand and excess cash flow from the non-operated joint venture lands in the Thrace Basin, where we are targeting to re-invest about 50% of the cash flow to drill up to 10 gross wells and grow production by 5 to 10%. Drilling on the joint venture lands is scheduled to resume in May after a hiatus of about four months during the wet season."

Q4 2014 RESULTS AT A GLANCE

• Tied-in five new conventional gas wells including three new discoveries
• Net sales 1,180 boe/d
• Funds flow from operations $3.7 million
• Working capital surplus $10.0 million
• Natural gas price realization $10.62/Mcf
• Operating netback $46.22/boe
• Net capital expenditures $2.8 million

(Results exclude discontinued Canadian operations. See below for definitions and advisories)

OPERATIONAL HIGHLIGHTS

• Net petroleum and natural gas sales in Turkey in Q4 2014 averaged 1,180 barrels of oil equivalent per day ("boe/d"), which was 18% higher than sales in Q3 2014, including 7.0 million cubic feet per day ("MMcf/d") of natural gas and 10 barrels of oil per day ("bbl/d").
• Net corporate petroleum and natural gas sales to date in Q1 2015 have averaged approximately 1,250 boe/d.
• The Turkish government increased domestic natural gas prices, denominated in Turkish Lira ("TL"), by 9% effective October 1, 2014, which resulted in an increase in the Corporation's average Q4 2014 natural gas price realization to $10.62 per thousand cubic feet ("Mcf"). 

Thrace Basin – TBNG-PTI JV (40% Working Interest)

• Drilled the successful Gurgen-2 well in Q4 2014 as the first appraisal well on the Gurgen-1 discovery in the Osmanli area on the joint venture lands acquired from Thrace Basin Natural Gas (Turkiye) Corporation ("TBNG") and Pinnacle Turkey Inc. ("PTI") (the "TBNG-PTI JV"). Both Gurgen wells were tied-in during Q4 2014 and produced at an aggregate initial 30-day rate ("IP30") of 6.6 MMcf/d (gross).
• Tied-in three additional wells in the fourth quarter (Tavanli-1, Biyikali-2 sidetrack and Guney Osmanli-3), which in aggregate produced at an average IP30 rate of 2.9 MMcf/d (gross).
• Completed three other workovers on shallow gas wells during Q4 2014.
• Continued to make good progress with the General Directorate of Petroleum Affairs ("GDPA") in seeking to convert essentially all of its joint venture and 100% working interest exploration licences into new exploration licences or new production leases over part of certain existing exploration licences under the licencing terms of the new petroleum law adopted by Turkey in May 2013.
• During Q4 2014, Valeura and its joint venture partners were awarded four new production leases in the TBNG-PTI JV over part of two existing exploration licences, three new production leases in the Edirne area to replace part of the expiring exploration licence and two new exploration licences in the Gaziantep area to replace the existing exploration licence. These changes resulted in a 4% reduction to the gross and net acreage holdings of the Corporation as at December 31, 2014. The Corporation's current land holdings in Turkey comprise 0.96 million gross acres (0.42 million net acres).
• In January 2015, drilled a second appraisal well Gurgen-3 to a depth of 1,803 metres in the Osmancik formation. The Gurgen-3 well is located approximately 500 metres southeast of Gurgen-2 in separate, smaller uplifted fault compartment. The log analysis indicated approximately 18 metres of net gas pay at an average porosity of 18% at the top of the Osmancik. Lower intervals that were gas bearing in the Gurgen-1 and 2 wells appeared to be wet in Gurgen-3.  The Gurgen-3 well was cased to a depth of 1,630 and has produced at an IP30 rate of approximately 1.1 MMcf/d (gross) from approximately 12 metres of perforations.

(See advisories below regarding initial production rate disclosure)

Thrace Basin – Banarli Exploration Licence (100% Working Interest)

• Executed a contract to acquire approximately 150 square kilometres of new 3D seismic on the Banarli exploration licence commencing in May or June 2015, depending on weather conditions. The expected all-in cost to acquire, process and interpret the seismic is estimated at $4.9 million (gross and net).
• Valeura's application to convert the Banarli exploration licence to the new licencing terms remains pending. The Corporation believes that the conversion is potentially achievable before mid-2015. There is no certainty that such a conversion can be achieved and timing remains uncertain. (See the Corporation's 2014 AIF for a detailed description of the old and new licencing terms in Turkey).
• Valeura continued its process to seek a joint venture partner to participate in funding an exploration drilling program in the deeper horizons at Banarli below approximately 2,500 metres, targeting a potential basin-centered gas play. Moyes & Co., an internationally active acquisition and divestment firm, is assisting in the farm-out process.
• Concurrently, the TBNG-PTI JV has been in active discussions regarding a potential farm-in on the deeper horizons in certain of the joint venture lands, contingent on the successful conversion of the associated licences under the new petroleum law in Turkey, amongst other conditions. There is no certainty that a deep farm-in transaction will be completed with respect to the TBNG-PTI JV lands or Banarli licence, or the timing thereof.

FINANCIAL HIGHLIGHTS

• Funds flow from operations of $3.7 million in Q4 2014 was up 21% from Q3 2014 due primarily to higher sales volumes and higher natural gas price realizations. Funds flow from operations in Q4 2014 was essentially unchanged from Q4 2013, with increased sales volumes and prices offset by higher general and administrative expenses.  Funds flow from operations in 2014 of $13.6 million was 38% higher than 2013 due primarily to higher volumes, lower general and administrative expenses and lower operating costs, partially offset by lower natural gas price realizations. (See discussion below regarding non-IFRS measures).
• Net capital expenditures of $2.8 million in Q4 2014 were up 12% from Q3 2014 due to higher drilling and tie-in expenditures, and down 51% from Q4 2013 due to lower drilling and fracking expenditures. Capital expenditures of $10.8 million in 2014 were also down 60% from 2013 reflecting lower drilling and fracking expenditures.
• The average natural gas price realization in Turkey of $10.62 per Mcf in Q4 2014 was up 10% and 7% from Q3 2014 and Q4 2013, respectively, due primarily to a 9% increase in the reference price for domestic sales in Turkey (denominated in TL). The average natural gas price realization of $10.23 per Mcf in 2014 was down 3% from 2013 due to the weakening of the TL, which more than offset the impact of the increased benchmark price effective October 1, 2014.
• The corporate average operating netback of $46.22 per boe in Q4 2014 was up 5% from Q3 2014 due primarily to higher natural gas price realisations partially offset by higher unit operating costs, and up 6% from Q4 2013 due primarily to higher natural gas price realisations. The average operating netback of $45.01 per boe in 2014 was up 3% from 2013 due primarily to lower unit operating costs, partially offset by lower natural gas price realizations. (See discussion below regarding non-IFRS measures).
• The Corporation had a working capital surplus of $10.0 million, including cash and cash equivalents of $5.9 million, as at December 31, 2014. This working capital surplus is up 47% from $6.8 million at year-end 2013.
• Additional financial and operating results are summarized in the Table 1 below.

Table 1 Financial and Operating Results Summary ⁽¹⁾

		Three Months Ended December 31, 2014	Three Months Ended September 30, 2014	Year Ended Decmber 31, 2014	Three Months Ended December 31, 2013	Year Ended December 31, 2013
Financial (thousands of Canadian dollars, except share and per share amounts)
Petroleum and natural gas revenues		6,921	5,330	24,998	6,347	21,084
Funds flow from continuing operations ^(2)		3,654	3,011	13,586	3,672	9,864
Net income (loss) from continuing operations		697	(171)	1,090	(6,854)	(14,571)
Capital expenditures (net of asset dispositions)		2,822	2,515	10,846	5,809	26,952
Net working capital surplus		10,044	9,865	10,044	6,834	6,834
Cash and cash equivalents		5,928	5,974	5,928	6,511	6,511
Common shares outstanding
	Basic	57,906,135	57,906,135	57,906,135	57,906,135	57,906,135
	Diluted	77,146,102	77,146,102	77,146,102	75,819,352	75,819,352
Share trading
	High	0.45	0.57	0.78	0.43	1.15
	Low	0.30	0.33	0.30	0.27	0.27
	Close	0.38	0.33	0.38	0.30	0.30
Operations
Production
	Crude oil (bbl/d)	10	7	8	14	16
	Natural Gas (Mcf/d)	7,022	5,943	6,812	6,812	5,494
	boe/d (@ 6:1) ^(3)	1,180	997	1,143	1,149	932
Average reference price		11.02	10.14	10.39	10.44	10.89
	BOTAS Reference ($ per Mcf) ^(4)
Average realized price
	Crude oil ($ per bbl)	62.66	82.18	78.64	97.64	97.36
	Natural gas - Turkey ($ per Mcf)	10.62	9.66	9.96	9.93	10.23
Average Operating Netback ($ per boe @ 6:1) ^(2) (3)		46.22	43.85	45.01	43.71	43.62

Notes:
(1)	The above table includes figures from continuing operations in Turkey.  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 to 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 and purchases the majority of Turkey's natural gas imports.  BOTAS regularly posts prices and its Organized Industrial Zones natural gas wholesale tariff ("BOTAS Reference Price") is shown herein. See the 2014 AIF for further discussion.

OUTLOOK

The Corporation expects to execute a capital expenditure budget of up to $18 to 20 million (net) in Turkey in 2015, focused on natural gas development in the Thrace Basin, contingent on the level of operating cash flow from the TBNG-PTI JV lands. The work program and budget aims to achieve the following key objectives in 2015:

• Offset natural declines and achieve 5 to 10% production growth in 2015 on the TBNG-PTI JV lands from a program funded by available cash and operating cash flow;   
• Pursue the shallow conventional gas play on Valeura's 100% Banarli licence with new 3D seismic and drill a licence retention well and up to two additional wells, contingent on the seismic results and the Corporation's cash position; and
• Seek a farm-in partner(s) to pursue the deep basin-centered gas play on the TBNG-PTI JV lands and Banarli.

(See advisories below regarding outlook disclosures)

TBNG-PTI JV (Valeura 40% WI)

The planned work program on the non-operated TBNG-PTI JV lands in 2015 includes up to 10 new wells (gross), balanced between lower cost conventional wells targeting the Osmancik formation, building on the successful 2014 shallow gas exploration program in the Osmanli area, and tight gas wells (drill and frac) targeting the Mezardere formation. The program is also expected to include a selective program of tight gas well re-entry fracs and workovers on conventional gas wells.

Total capital expenditures on the TBNG-PTI JV lands are budgeted at up to $8.0 to 9.0 million (net).

Banarli Exploration Licence (Valeura 100% WI)

With respect to program on the operated Banarli exploration licence, Valeura plans to acquire approximately 150 square kilometres of new 3D seismic in 2015 on the southern part of the licence to overlap the recent Osmanli 3D seismic on the TBNG-PTI JV lands. The seismic is targeting to better image more than 15 exploration leads that have been identified on the existing 2D seismic on the licence.

The 2015 Banarli work program also includes at least one and up to three exploration wells targeting the Osmancik formation and top of the Mezardere formation to a depth of approximately 2,500 metres, contingent on the results from the new 3D seismic and the Corporation's cash position at the time. The average cost to drill, complete and test each well is estimated at $2.1 million (gross and net). Drilling is targeted to commence late in the third quarter or early in the fourth quarter depending on the timing of the 3D seismic survey. Contingent funds of $1.2 million (gross and net) are also included in the 2015 budget for a trunk-line to tie-in at least one well, assuming drilling success and the ability to negotiate a transportation and marketing arrangement to tie-in production.

Total capital expenditures at Banarli for the shallow gas play are budgeted at up to $10.0 to 11.0 million (gross and net). 

2014 YEAR-END CORPORATE RESERVES REPORT

The Corporation has completed its independent reserves evaluation as at December 31, 2014. This evaluation was conducted by DeGolyer and MacNaughton ("D&M") of Dallas, Texas for the Corporation's properties in Turkey in its report dated March 10, 2015 (the "D&M Reserves Report"). This evaluation was prepared using guidelines outlined in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and is in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional reserves information as required under NI 51-101 is included in the 2014 AIF filed on SEDAR. All of the Corporation's reserves are located in Turkey.

2014 YEAR-END HIGHLIGHTS

• Replaced 122% of production with 1P reserves additions and 214% with 2P reserves additions
• 1P reserves up 5% to 1.7 MMboe and 2P reserves up 9% to 5.8 Mmboe (company gross)
• 1P reserves value $40 million ($0.68 per share) and 2P reserves value $108 million ($1.86 per share) (NPV₁₀ before tax)
• 2P reserves life index ("RLI") of 13.5 years (based on annualized Q4 2014 production) requiring future development capital ("FDC") of $84 million
• 2P finding and development cost ("F&D") of $25.66/boe including changes to FDC yielding a recycle ratio of 1.75; F&D cost of  $12.64/boe excluding FDC yielding a recycle ratio of 3.56

COMPANY RESERVES SUMMARY

The following Table 2 summarizes company reserves in Turkey and associated net present value discounted at 10% ("NPV₁₀") before tax at December 31, 2014 and December 31, 2013 using forecast prices.

Table 2 Company Gross Reserves Volumes and Values ^(1)(2)(3)(4)

		RESERVES (Mboe)			NET PRESENT VALUE AT 10% BEFORE TAX ($ MILLIONS - $MM)
		2014	2013	% CHANGE	2014	2013	% CHANGE
Proved
	Developed producing	639	746	-14	22.2	30.0	-26
	Developed non-producing	448	318	+41	9.9	8.8	+13
	Undeveloped	651	584	+11	7.5	6.3	+19
Total Proved (1P)		1,738	1,648	+5	39.6	45.1	-12
Probable		4,066	3,680	+10	68.1	80.1	-15
Total Proved Plus Probable (2P)		5,804	5,328	+9	107.7	125.2	-14
Possible		4,564	4,971	-8	84.7	117.1	-28
Total Proved Plus Probable Plus Possible (3P)		10,368	10,299	+1	192.4	242.3	-21

Notes:
(1)	See Oil and Gas Advisories and Reserve and Resource Definitions below.
(2)	D&M's valuations for reserves in Turkey are prepared in US$ and have been converted for purposes of this illustration to Cdn$ assuming a $Cdn/$US exchange rate of 0.86 for the year-end 2014 values and 0.94 for the year-end 2013 values.
(3)	The forecast prices used in the calculations of the present value of future net revenue for year-end 2014 are based on the D&M December 31, 2014 forecast prices, which are included in the 2014 AIF filed on SEDAR. The natural gas forecast prices (in US$/Mcf) are lower than 2013 reflecting a weaker exchange rate for the TL, the pricing basis for Turkish natural gas sales.
(4)	Due to rounding, summations in the table may not add.

Turkey

The following tables and commentary summarize information contained in the D&M Reserves Report for Turkey.

D&M evaluated reserves as at December 31, 2014 on the TBNG-PTI JV lands (40% working interest), the Edirne lands in the Thrace Basin (35% working interest) and the Gaziantep lands in the Anatolian Basin (26% working interest). The reserves are primarily natural gas but small oil volumes are assigned to the Bati Kazanci-4 well (40% working interest) in the Thrace Basin and the Alibey-1 horizontal well (26% working interest) in the Anatolian Basin.

The 2014 year-end reserves by principal product type are summarized in Table 3 below.

Table 3 2014 Year-end Company Gross Reserves Volumes by Principal Product Type ⁽¹⁾

RESERVES CATEGORY	LIGHT/MEDIUM OIL (Mbbl)	NATURAL GAS (Bcf)	TOTAL OIL EQUIVALENT (Mboe)
Proved	79	10.0	1,738
Probable	48	24.1	4,066
Total proved plus probable	127	34.1	5,804
Possible	91	26.8	4,564
Total proved, probable and possible	218	60.9	10,368

Notes:
(1)	See Oil and Gas Advisories and Reserve and Resource Definitions below.

The forecast oil and natural gas prices and costs escalation rates used in the D&M Reserves Report are shown in Table 4 below.

Table 4 Forecast Prices and Cost Escalation Rates ⁽¹⁾

YEAR	NATURAL GAS		CRUDE OIL		COST ESCALATION
	TBNG GAS PRICE (US$/Mcf)	EDIRNE GAS PRICE (US$/Mcf)	ALIBEY OIL PRICE (US$/bbl)	KAZANCI OIL PRICE (US$/bbl)	%/YEAR
2015	9.10	7.92	58.65	48.30	0.0
2016	9.10	7.92	64.09	52.78	2.0
2017	9.28	8.08	69.73	57.42	2.0
2018	9.47	8.24	75.57	62.23	2.0
2019	9.66	8.40	81.61	67.21	2.0
2020+	+2.0%/year thereafter	+2.0%/year thereafter	+2.0%/year thereafter	+2.0%/year thereafter	+2.0%/year Thereafter

Notes:
(1)	The forecast prices used in the calculation of the present value of future net revenue are based on the D&M December 31, 2014 forecast prices, which are included in the 2014 AIF filed on SEDAR.

Thrace Basin

The majority of the Corporation's gross reserves are natural gas located in the Thrace Basin in northwest Turkey west of Istanbul. The reserve assessment encompassed shallow gas reserves in the Danismen and Osmancik formations and certain deeper, tight gas reserves in the underlying Mezardere, Teslimkoy and Kesan formations.

Reserves Reconciliation

Table 5 below sets forth a reconciliation of reserves changes in 2014.

Table 5 2014 Year-end Company Gross Reserves Reconciliation

CHANGES		1P (Mboe)	2P (Mboe)
At December 31, 2013		1,648	5,328
	Technical Revisions	253	531
	Discoveries & Extensions	254	362
	Economic Factors	0	0
	Production	417	417
At December 31, 2014		1,738	5,804

Reserve Life Index ("RLI") ⁽¹⁾

Table 6 below sets forth the reserve life index for total proved and proved plus probable reserves based on the annualized Q4 production rates of 944 boe/d, 1,149 boe/d and 1,180 boe/d for the years 2012, 2013 and 2014, respectively.

RESERVE LIFE INDEX (YEARS)	2014	2013	2012
Total Proved	4.0	3.9	2.9
Total Proved plus Probable	13.5	12.7	13.0

Notes:
(1)	Valeura assessment.

Table 6 below sets forth finding and development costs for 2014, 2013 and the weighted average for the three years 2012 to 2014.

Table 6 Finding and Development ("F&D") Costs ⁽¹⁾⁽²⁾

	2014		2013		2012 – 2014 WEIGHTED AVERAGE
	1P	2P	1P	2P	1P	2P
F&D Costs Excluding Future Development Cost ("FDC")
Exploration and Development Capital Expenditures - $M	11,290	11,290	26,878	26,878	67,737	67,737
Exploration and Development Reserve Additions including Revisions - Mboe	507	893	980	1,180	2,086	5,260
Finding and Development Cost – $/boe	22.27	12.64	27.43	22.78	32.47	12.88
F&D Recycle Ratio - $/$	2.02	3.56	1.59	1.92	1.31	3.29
F&D Costs Including Future Development Cost
Exploration and Development Capital Expenditures - $M	11,290	11,290	26,878	26,878	67,737	67,737
Exploration and Development Change in FDC  - $M	-246	11,628	6,695	10,458	19,150	77,108
Exploration and Development Capital including Change in FDC - $M	11,044	22,918	33,573	37,336	86,887	144,845
Exploration and Development Reserve Additions including Revisions - Mboe	507	893	980	1,180	2,086	5,260
Finding and Development Cost – $/boe	21.78	25.66	34.26	31.64	41.65	27.54
F&D Recycle Ratio - $/$ ^(3)	2.07	1.75	1.27	1.38	1.02	1.54
Operating Netback - $/boe ^(4)	45.01		43.62		42.40

Notes:
(1)	Valeura assessment.
(2)	See Valeura's management's discussion and analysis and annual information forms for the years ending 2011, 2012, 2013 and 2014 for details on FDC. The aggregate of the F&D costs incurred in the most recent financial year and the change during the year in estimated FDC generally will not reflect the total F&D costs related to reserves additions for that year.
(3)	Recycle ratio is calculated as operating netback divided by F&D cost for the applicable period.
(4)	Operating netback is calculated as petroleum and natural gas sales less royalties, production expenses and transportation costs. See MD&A for further discussion.

Contingent Resources

The Corporation has not updated the contingent resources assessment for the Thrace Basin carried out by D&M as at December 31, 2012, which was summarized in Valeura's 2012 annual information form. Any decision to update D&M's contingent resources assessment will be dependent on further results from planned tight gas drilling on the TBNG-PTI JV lands and exploration drilling on the Banarli exploration licence 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 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 to 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 wellhead.

The initial on-stream production rates disclosed in this news release are preliminary in nature and may not be indicative of stabilized on-stream production rates. Initial on-stream production rates 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. All natural gas rates and volumes are presented net of any load fluids.

The reserve estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

The net present value of estimated future net revenue disclosed in this news release should not be construed as the current market value of estimated crude oil, natural gas liquids and natural gas reserves attributable to Valeura's properties. The estimated discounted future net revenue from reserves are based upon price and cost estimates which may vary from actual prices and costs and such variance could be material. Actual future net revenue will also be affected by production, supply and demand for crude oil and natural gas, curtailments or increases in consumption by purchasers and changes in governmental regulations or taxation.

RESERVE AND RESOURCE DEFINITIONS 

''Reserves'' are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed.  Reserves are classified according to the degree of certainty associated with the estimates.

"Company gross reserves" are the Company's working interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Company.

"Proved" or "1P" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable ("2P") reserves.

"Possible" reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible ("3P") reserves.

"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production but are shut in and the date of resumption of production is unknown.

"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

"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. Contingent resources have an associated chance of development (economic, regulatory, market and facility, corporate commitment or political risks). The estimates herein have not been risked for the chance of development. There is no certainty that the contingent resources will be developed and, if they are developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the contingent resources. 

ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION

This news release contains certain forward-looking statements including, but not limited to: the Corporation's 2015 work program and budget, operational plans (seismic, drilling, fracking and workovers) and capital expenditures on the TBNG-PTI JV lands and the Banarli licence; expected production growth on the TBNG-PTI JV lands in 2015; the planned seismic and drilling program on the Banarli licence in 2015 and the associated timelines; the ability to negotiate a transportation and marketing arrangement with the TBNG-PTI JV to tie-in at least one well at Banarli, assuming drilling success;  plans to perforate additional net pay in the Gurgen wells and the timing thereof; the availability of operating cash flow and the ability to finance development; tieing-in new wells and getting these on-stream; the timing, estimated costs and ability to fund each of the foregoing; the plans to attract a farm-in partner to drill the deep, potential basin-centered gas play on the Banarli licence; the plans to attract a farm-in partner on the deeper horizons in certain of the TBNG-PTI JV lands; and, the ability to convert the Banarli licence and other TBNG-PTI JV licences to 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. Statements related to "reserves" or "contingent resources" are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources can be profitably produced in the future.

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 seismic, drilling, fracking and re-completion activity; future production rates, capital efficiencies and associated cash flow; future capital and other expenditures (including the amount and nature thereof); 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 2015 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; uncertainty regarding the amount of operating cash flow and the ability to reduce costs and achieve capital efficiencies; 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; 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 Turkish Lira); the risk of fluctuations in foreign exchange rates, particularly the Turkish Lira; 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 2014 AIF for a detailed discussion of the risk factors.

Any financial outlook or future oriented financial information in this news release, as defined by applicable securities legislation, has been approved by management of Valeura. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

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