Valeura Announces Fourth Quarter 2015 Financial and Operating Results and Year-End 2015 Reserves

CALGARY, March 8, 2016 /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, 2015, audited results for the year ended December 31, 2015, year-end 2015 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 2015 annual information form ("2015 AIF"), have been filed on SEDAR at www.sedar.com and posted on the Corporation's website at www.valeuraenergy.com.

"Valeura recorded solid results in the fourth quarter, realizing strong natural gas sales prices and operating netbacks in Turkey averaging $9.93 per Mcf and $44.56 per boe, respectively, and delivering $1.6 million in funds flow from operations", said Jim McFarland, President and Chief Executive Officer. "These standout operating netbacks in Turkey reflect strong natural gas pricing, a competitive 12.5% government royalty regime and low operating costs. Net sales in the fourth quarter, all non-operated, were up slightly from the third quarter despite nominal capital expenditures on the joint venture lands in the Thrace Basin."

"We are encouraged that the first two exploration wells drilled on our 100% owned and operated Banarli licences have confirmed over-pressure in the Teslimkoy formation below 2,500 metres. Bati Gurgen-1 is expected to be on-stream shortly and producing conventional gas from the Osmancik formation. Yayli-1 is undergoing completion and fracking operations in the over-pressured tight gas sands in the Teslimkoy formation. Both wells represent important steps in our strategic shift to our operated assets."

"We also successfully replaced 125% of 2015 production with proved reserves additions, increasing proved reserves by 5% to 1.8 million boe at year end 2015 with a value of $0.71 per share. Proved plus probable reserves at year-end 2015 were down 6% to 5.5 MMboe due to production and technical revisions associated with a more conservative development program for the normally-pressured tight gas sands on the joint venture lands, partially offset by the Bati Gurgen-1 discovery at Banarli, which added proved plus probable reserves of 4.9 Bcf or 0.8 MMboe. However, the proved plus probable reserves value was up 8% to $2.02 per share due to a weaker Canadian dollar. "

Q4 2015 RESULTS AT A GLANCE

• Drilled first two Banarli exploration wells (Valeura 100% working interest):
  • Bati Gurgen-1 (first gas expected imminently); and
  • Yayli-1 (completion and fracking operations underway)
• Net sales 809 boe/d
• Funds flow from operations $1.6 million
• Working capital surplus $7.3 million
• Natural gas price realization $9.93/Mcf
• Operating costs $6.85/boe
• Operating netback $44.56/boe
• Net capital expenditures $6.1 million

(See below for definitions and advisories)

OPERATIONAL HIGHLIGHTS

• Net petroleum and natural gas sales in Turkey in Q4 2015 averaged 809 barrels of oil equivalent per day ("boe/d"), which were up 2% from Q3 2015 and down 31% from Q4 2014. Net sales in Q4 2015 included 4.8 million cubic feet per day ("MMcf/d") of natural gas and 8.0 barrels of oil per day ("bbl/d").
• Net corporate petroleum and natural gas sales in 2015 averaged 966 boe/d, which were down 15% from 2014. Lower volumes in 2015 reflect the impact of reduced drilling and fracking operations on the joint venture lands acquired from Thrace Basin Natural Gas (Turkiye) Corporation ("TBNG") and Pinnacle Turkey Inc. ("PTI") (the "TBNG-PTI JV"). Valeura shifted approximately 83% of its capital expenditures in 2015 to the 100% owned and operated Banarli licences in 2015, including $10.9 million for 3D seismic and drilling. 

Thrace Basin – Banarli Exploration Licences (Valeura 100% Working Interest)

Bati Gurgen-1 Well

• Spudded the first exploration well Bati Gurgen-1 on the Banarli licences on November 10, 2015 and drilled the well to a measured depth of 2,735 metres into the Teslimkoy member of the Mezardere formation. Wireline log analysis indicated 32 metres of aggregate net pay in the Danismen and Osmancik formations and thinner net pay in tight sands in the Teslimkoy.
• Carried out a diagnostic fracture injection test in a short interval in the Teslimkoy at a depth of 2,560 metres, which confirmed that the formation is over-pressured, consistent with Valeura's geological model of a potential basin-centered gas play below 2,500 metres on the Banarli licences.
• Completed a 13-metre interval in the Osmancik formation at a depth of 1,480 metres, which flowed natural gas at an initial restricted rate of 3.4 MMcf/d on a 24-hour production test. The shallower Danismen formation is also prospective for conventional gas and may also be completed within one or two months following initial on-stream monitoring of the Osmancik formation alone.
• Completed the tie-in of the well through a new 8-inch, 3.2 kilometre pipeline to an existing dehydration facility at the Gurgen-1 well on the adjacent TBNG-PTI JV lands (Valeura 40% working interest).
• First gas from Bati Gurgen-1 expected in the next few days and an operational update will be provided once on-stream operations have stabilized.
• The final cost to drill, complete, test and tie-in the Bati Gurgen-1 well was $3.3 million, as budgeted.

Yayli-1 Well

• Spudded the second Banarli exploration well Yayli-1 on December 1, 2015 and drilled the well to a measured depth of 2,914 metres in the Teslimkoy. Wireline log analysis indicated 14 metres of net pay in the Osmancik and 128 metres of net pay in tight sands in the Teslimkoy.
• Carried out a diagnostic fracture injection test in a 13 metre interval in the Teslimkoy at a depth of 2,865 metres, which confirmed the formation is over-pressured to the same extent as measured at the Bati Gurgen-1.
• Commenced a multi-stage Teslimkoy frack program to be carried out and evaluated on a sequential basis working upward from the bottom of the well. A small frack was carried out at 2,865 meters to stimulate a relatively thin 13 metre net pay interval as an initial calibration point, which yielded producible gas with small amounts of condensate. However, only 55% of the frack fluids have been recovered to date due to equipment limitations in unloading fluid from the well, which could be limiting gas flow rates. Therefore, further frack operations are on hold until late March when a larger coiled tubing unit is expected to be available to facilitate faster and more complete frack fluid recovery. A more comprehensive operational update will follow once the fracking and testing program is completed.
• The final estimated total cost to drill, frack, complete, test and tie-in the Yayli-1 well is $4.5 to 5.0 million, depending on the final extent of the frack operations.

Other

• Applied for two new exploration licences contiguous with the Banarli licences. The bids remain under review by the General Directorate of Petroleum Affairs of the Republic of Turkey ("GDPA").
• Continued the process to seek a joint venture partner to participate in funding an exploration drilling program in the deeper horizons at Banarli, targeting a potential basin-centered gas play.

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

• The GDPA has approved a TBNG-PTI JV application for two production leases G18-b1-1 and G18-b2-1 which were carved out from expired exploration licence 3931 in the Tekirdag area. The new leases cover an area of 42,077 acres (gross). Two other production lease applications (F19-d3-1 and F19-c3-1) have been submitted to the GDPA in the Tekirdag area as carve-outs from expired exploration licences 3934 and 4126.
• The TBNG-PTI JV has continued its parallel process to seek a farm-in partner to explore the deeper horizons on certain TBNG-PTI JV lands. All discussions with currently interested parties are at the preliminary stage. There is no certainty that a deep farm-in transaction will be completed with respect to the TBNG-PTI JV lands or at Banarli, or the timing of final terms thereof.

FINANCIAL HIGHLIGHTS

• The average natural gas price realization in Turkey of $9.93 per Mcf in Q4 2015 was up marginally from Q3 2015 and down 6% from Q4 2014 due to fluctuations in the Turkish Lira exchange rate. The average natural gas price realization of $10.20 per Mcf in 2015 was up marginally from 2014 due to a 9% increase in the reference price for domestic sales in Turkey effective October 1, 2014, partially offset by a weaker Turkish Lira.
• The average operating netback of $44.56 per boe in Q4 2015 was essentially unchanged from Q3 2015 and down 4% from Q4 2014 due to lower natural gas price realizations, partially offset by lower unit operating costs, and up marginally from Q3 2014 due to higher natural gas price realizations, partially offset by higher unit operating costs. The average operating netback of $46.48 in 2015 was marginally higher than 2014 due to higher natural gas price realizations and lower unit operating costs. (See discussion below regarding non-IFRS measures)
• Working capital surplus at December 31, 2015 was $7.3 million, including cash of $7.0 million.
• Funds flow from operations of $1.6 million in Q4 2015 was down 18% and 56% from Q3 2015 and Q4 2014, respectively, reflecting lower sales volumes, higher business development expenses and higher realized foreign exchange losses. Funds flow from operations in 2015 of $10.2 million was 25% lower than 2014 due to lower sales volumes, higher business development expenses and higher realized foreign exchange losses. (See discussion below regarding non-IFRS measures)
• Net capital expenditures of $6.1 million in Q4 2015 were up 723% and 116% from Q3 2015 and Q4 2014, respectively, due to higher drilling and completion expenditures on the Banarli licences, partially offset by lower drilling expenditures on the TBNG-PTI JV lands. Net capital expenditures of $13.2 million in 2015 were up 22% from 2014 due to higher seismic, drilling and completion expenditures on the Banarli licences, partially offset by lower drilling and fracking expenditures on the TBNG-PTI JV lands.
• Additional financial and operating results are summarized in the Table 1 below.

Table 1 Financial and Operating Results Summary ⁽¹⁾

(thousands of Canadian dollars, except share or per share amounts)		Three Months Ended December 31, 2015	Three Months Ended September 30, 2015	Year Ended December 31, 2015	Three Months Ended December 31, 2014	Year Ended December 31, 2014
Financial
Petroleum and natural gas revenues		4,425	4,309	21,543	6,921	24,998
Funds flow from continuing operations ^(2)		1,600	1,949	10,185	3,654	13,586
Net income (loss) from continuing operations		287	(169)	(562)	697	1,090
Capital expenditures (net of asset dispositions)		6,100	741	13,192	2,822	10,846
Net working capital surplus		7,253	11,335	7,253	10,044	10,044
Cash and cash equivalents		6,973	7,972	6,973	5,928	5,928
Common shares outstanding
	Basic	57,906,135	57,906,135	57,906,135	57,906,135	57,906,135
	Diluted	76,352,352	76,352,352	76,352,352	77,146,102	77,146,102
Share trading
	High	0.66	0.57	0.71	0.45	0.78
	Low	0.36	0.36	0.36	0.30	0.30
	Close	0.66	0.42	0.66	0.38	0.38
Operations
Production
	Crude oil (bbl/d)	8	7	8	10	8
	Natural Gas (Mcf/d)	4,805	4,723	5,745	7,022	6,812
	boe/d (@ 6:1) ^(3)	809	794	966	1,180	1,143
Average reference price
	Brent ($/bbl)	58.16	65.91	66.88	86.83	109.29
	BOTAS Reference ($/Mcf) ^(4)	10.07	10.07	10.32	11.02	10.39
Average realized price
	Crude oil ($ per bbl)	44.51	48.79	50.35	62.66	78.64
	Natural gas - Turkey ($/Mcf)	9.93	9.85	10.20	10.62	9.96
Average Operating Netback
($ per boe @ 6:1) ^(2) (3)		44.56	44.50	46.48	46.22	45.01

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)	Barrel of oil equivalent ("boe") 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 2015 AIF for further discussion.

OUTLOOK

The Corporation is continuing to execute its strategy to shift emphasis from its non-operated 40% working interest in the TBNG-PTI JV to its 100% owned and operated Banarli licences in the Thrace Basin.

The Corporation expects to provide further guidance on anticipated capital expenditures and production volumes in 2016 once the fracking program is completed on the Yayli-1 well and production performance is available from the Bati Gurgen-1 and Yayli-1 wells at Banarli.

The Corporation will continue to seek farm-in partner(s) to accelerate delineation of the potential basin-centered gas play on the Banarli licences and certain TBNG-PTI JV lands.

(See advisories below regarding outlook disclosures)

2015 YEAR-END CORPORATE RESERVES REPORT

The Corporation has completed its independent reserves evaluation as at December 31, 2015. 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 8, 2016 (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 2015 AIF filed on SEDAR. All of the Corporation's reserves are located in Turkey.

HIGHLIGHTS

• Replaced 125% of production with 1P reserves additions (including Revisions)
• 1P reserves up 5% to 1.8 MMboe and 2P reserves down 6% to 5.5 MMboe (company gross)
• 1P reserves value $41 million ($0.71 per share) and 2P reserves value $117 million ($2.02 per share) (NPV₁₀ before tax)
• 2P reserves life index ("RLI") of 18.5 years (based on annualized Q4 2015 production) requiring future development capital of $95 million

COMPANY RESERVES SUMMARY

Table 2 summarizes company reserves in Turkey and associated net present value discounted at 10% ("NPV₁₀") before tax at December 31, 2015 and December 31, 2014 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)
		2015	2014	% CHANGE	2015	2014	% CHANGE
Proved
	Developed producing	509	639	-20	17.3	22.2	-22
	Developed non-producing	513	448	+15	13.4	9.9	+35
	Undeveloped	805	651	+24	10.4	7.5	+39
Total Proved (1P)		1,827	1,738	+5	41.1	39.6	+4
Probable		3,634	4,066	-11	75.9	68.1	+11
Total Proved Plus Probable (2P)		5,461	5,804	-6	117.0	107.7	+9
Possible		3,121	4,564	-32	71.6	84.7	-15
Total Proved Plus Probable Plus Possible (3P)		8,582	10,368	-17	188.6	192.4	-2

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 0.72 for the year-end 2015 values and 0.86 for the year-end 2014 values.
(3)	The forecast prices used in the calculations of the present value of future net revenue for year-end 2015 are based on the D&M December 31, 2015 forecast prices, which are included in the 2015 AIF filed on SEDAR. The natural gas forecast prices (in US$/Mcf) are lower than 2014 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.

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

D&M evaluated reserves as at December 31, 2015 on the Company's Banarli Licence (100% working interest) and 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 a number of wells with the majority of the oil reserves attributed to the Alibey area (26% working interest) in the Anatolian Basin.

The 2015 year-end reserves by principal product type are summarized in Table 3.

Table 3 2015 Year-end Company Gross Reserves Volumes by Principal Product Type ⁽¹⁾

RESERVES CATEGORY	LIGHT and MEDIUM CRUDE OIL (Mbbl)	CONVENTIONAL NATURAL GAS (Bcf)	TOTAL OIL EQUIVALENT (Mboe)
Proved	79	10.5	1,827
Probable	51	21.5	3,634
Total Proved Plus Probable	130	32.0	5,461
Possible	78	18.2	3,121
Total Proved Plus Probable Plus Possible	208	50.2	8,582

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

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

Table 4 Forecast Prices and Cost Escalation Rates ⁽¹⁾

YEAR	CONVENTIONAL NATURAL GAS			LIGHT AND MEDIUM CRUDE OIL			COST ESCALATION
	BANARLI (US$/Mcf)	TBNG (US$/Mcf)	EDIRNE (US$/Mcf)	BANARLI (US$/bbl)	ALIBEY (US$/bbl)	TBNG (US$/bbl)	%/YEAR
2016	7.18	8.00	7.96	39.00	45.76	39.00	0.0
2017	7.32	8.16	8.12	45.08	52.89	45.08	2.0
2018	7.47	8.32	8.28	47.51	55.74	47.51	2.0
2019	7.62	8.49	8.45	52.40	61.48	52.40	2.0
2020	7.77	8.66	8.62	56.69	66.51	56.69	2.0
2021	7.93	8.83	8.79	60.31	70.76	60.31	2.0
2022	8.09	9.01	8.96	65.74	77.13	65.74	2.0
2023	8.25	9.19	9.14	67.05	78.67	67.05	2.0
2024	8.41	9.37	9.33	68.39	80.25	68.39	2.0
2025	8.58	9.56	9.51	69.76	81.85	69.76	2.0
2026	8.75	9.75	9.70	71.15	83.49	71.15	2.0
2027	8.93	9.95	9.90	72.58	85.16	72.58	2.0
2028+	+2.0%/year thereafter	+2.0%/year thereafter	+2.0%/year thereafter	+2.0%/year thereafter	+2.0%/year thereafter	+2.0%/year thereafter	+2.0%/year Thereafter

Note:
(1)	The forecast prices used in the calculation of the present value of future net revenue are based on the D&M December 31, 2015 forecast prices, which are included in the 2015 AIF filed on SEDAR.

Table 5 sets forth a reconciliation of reserves changes in 2015.

Table 5 2015 Year-end Company Gross Reserves Reconciliation

CHANGES		1P (Mboe)	2P (Mboe)
At December 31, 2014		1,738	5,804
	Technical Revisions	183	-849 ^(1)
	Discoveries	259	859
	Economic Factors	0	0
	Production	-353	-353
At December 31, 2015		1,827	5,461

Note:
(1)	This negative technical revision reflects a more conservative development plan for the normally-pressured tight gas sands on the TBNG-PTI JV lands.

Table 6 sets forth the RLI for total proved and proved plus probable reserves based on the annualized Q4 production rates of 1,149 boe/d, 1,180 boe/d and 809 boe/d for the years 2013, 2014 and 2015, respectively.

Table 6 Reserve Life Index ("RLI") ⁽¹⁾⁽²⁾

RLI (YEARS)	2015	2014	2013
Total Proved	6.2	4.0	3.9
Total Proved Plus Probable	18.5	13.5	12.7

Notes:
(1)	See Oil and Gas Advisories below.
(2)	Valeura assessment.

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.

This news release contains metrics commonly used in the oil and natural gas industry, such as "operating netback" and "reserve life index ("RLI")". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

"Operating netback" is calculated using production revenues minus royalties and production expenses and transportation expenses calculated on a per boe basis.  

"Reserve life index" is calculated as total company share reserves divided by annual production.  

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Valeura's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.

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.

ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION

This news release contains certain forward-looking statements including, but not limited to: the anticipated timing of first gas from the Bati Gurgen-1 well; the ultimate extent of the Teslimkoy fracking program in the Yayli-1 well, the timing of the availability of a large coiled tubing unit and resumption of fracking operations, and the results thereof; planned tie-in of the Yayli-1 well and the timing thereof; the future completion of the Danismen formation in the Bati Gurgen-1 well and Osmancik formation in the Yayli-1 well; the planned drilling program on the Banarli licences and TBNG-PTI JV lands and the timing thereof; the extent of over-pressure below approximately 2,500 metres across the Banarli licences and certain TBNG-PTI JV lands and the potential for a basin-centered gas play; the availability of operating cash flow and the ability to finance development from existing cash and operating cash flow; tieing-in new wells and getting these on-stream; the timing, estimated costs and ability to fund each of the foregoing; and the plans to attract a farm-in partner(s) to drill the deep, potential basin-centered gas play on the Banarli licences and certain of the TBNG-PTI JV lands. 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" are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves 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 on the expected timelines; the prospectivity of the Banarli licences; future production rates, capital efficiencies 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; the ability to attract partners and negotiate farm-in agreements, in particular for deep exploration on certain TBNG-PTI JV lands and on the Banarli licences; 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 work programs and budgets are in part based upon expected agreement among joint venture 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 drilling, fracking and other specialized oilfield equipment and service providers, changes in the operator's or other partners' plans 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 availability of drilling rigs and equipment and 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 in 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 fluctuations in commodity pricing and BOTAS reference prices (denominated in Turkish Lira ("TL")); the risk of fluctuations in foreign exchange rates, particularly the TL; 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 2015 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