Valeura Announces Fourth Quarter 2016 Financial and Operating Results and Year-End 2016 Reserves
/NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES/
CALGARY, March 14, 2017 /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, 2016, audited results for the year ended December 31, 2016, year-end 2016 reserves and an update on subsequent developments. The complete quarterly reporting package for the Corporation, including the audited financial statements and associated management's discussion and analysis ("MD&A") and the 2016 annual information form ("2016 AIF"), have been filed on SEDAR at www.sedar.com and posted on the Corporation's website at www.valeuraenergy.com.
BUSINESS RESET COMPLETE
In the fourth quarter of 2016 the Corporation focused its efforts on transactional activity to reset the business and was successful in subsequently closing four inter-linked transactions in early 2017. These transactions have transformed the Corporation in terms of scaling-up the business, providing operational control and boosting financial capacity, which is expected to enable the Corporation to ramp-up drilling and grow production. The Corporation anticipates that these benefits will be evident through the course of 2017.
As a measure of this transformation, through the acquisition of the Corporation's joint venture partner TBNG, effective February 24, 2017, the Corporation doubled its participating interest in the TBNG JV lands, a core shallow-gas producing asset, and took over operatorship of the TBNG JV. The Corporation's patience in pursuing this long-standing acquisition target was rewarded by the successful negotiation of a series of concurrent transactions with Statoil, which provided cash to effectively fund the TBNG Acquisition in a non-dilutive way. The pro forma accretion metrics of the TBNG Acquisition are very strong, in both absolute and per share terms, as shown in the following table:
| Measure |
Pro Forma Accretion |
|
| Absolute |
Per Share (1) |
|
| Cash Flow (2) |
78% |
43% |
| Production (3) |
54% |
23% |
| 2P Reserves (4) |
89% |
51% |
| Notes: |
|
| (1) |
Based on 58.5 million shares pre-Offering (as defined below) and 73.1 million shares post-Offering. |
| (2) |
Based on annualized Q4 2016 cash flow. Cash flow herein is defined as revenue less royalties, operating costs and general and administrative ("G&A") expenses, including an estimated incremental G&A burden of $1.0 million associated with the TBNG Acquisition. |
| (3) |
Based on annualized Q4 2016 sales from TBNG's 41.5% working interest in the TBNG JV. |
| (4) |
Based on Valeura's allocation of DeGolyer and MacNaughton's estimate of Valeura's reserves for the TBNG JV lands at December 31, 2016 in their report prepared for Valeura dated March 14, 2017. |
These pro forma accretion metrics include the impact of an increase of 25% in the shares outstanding associated with the completion of the Offering, which provided gross proceeds of approximately $11 million, concurrent with the close of the TBNG Acquisition. These funds from the Offering and Statoil have boosted working capital to support a ramp-up of drilling in 2017.
"As our attention now turns from this complex transactional work to a focus on safe, efficient and effective operations in 2017, we have brought onboard a capable TBNG operating organization of more than 50 people and have hired a select number of new employees in Turkey as part of a comprehensive transition management plan including the handover of support functions previously provided by TransAtlantic", said Jim McFarland, President and Chief Executive Officer. "This business reset puts us in the best position in our history in terms of operational control. We had a good start to the year with a drilling success at the Dogu Atakoy-3 well and are excited about the catalysts in front of us. We are ready to move forward in the second quarter with an operated multi-well shallow gas drilling program and to spud the first deep 4,000 metre exploration well at Banarli, funded by Statoil, and also operated by Valeura," McFarland added.
Q4 2016 RESULTS AT A GLANCE
- Net sales 795 boe/d
- Funds flow from operations $0.9 million
- Working capital surplus $3.8 million
- Natural gas price realization $7.96/Mcf
- Operating netback $33.43/boe
- Net capital expenditures $0.5 million
- Executed definitive agreements for three transformational transactions – TBNG Acquisition, West Thrace Deep Rights Sale and Offering
- Subsequently closed the above transactions and the earlier Banarli Farm-in in January and February 2017 following Turkish government approvals
(See below for definitions and advisories)
TRANSACTIONAL HIGHLIGHTS
TBNG Acquisition
- As announced on February 24, 2017, an affiliate of Valeura closed a transaction with an affiliate of TransAtlantic Petroleum ("TransAtlantic") to acquire 100% of the shares of Thrace Basin Natural Gas (Turkiye) Corporation ("TBNG") for US$22 million effective March 31, 2016, which after closing adjustments was reduced to a cash payment of US$20.9 million (which includes US$3.1 million held in escrow pending a final reconciliation of the closing statement of adjustments) (the "TBNG Acquisition").
- TBNG holds a 41.5% participating interest in the TBNG JV and its acquisition increases Valeura's participating interest in the TBNG JV to 81.5% (subject to the West Thrace Deep Rights Sale) and establishes Valeura as the operator.
Offering
- As announced on February 24, 2017, Valeura issued 14,629,000 common shares of the Corporation, coincident with closing the TBNG Acquisition, pursuant to 14,629,000 subscription receipts previously issued by the Corporation at $0.75 per subscription receipt in connection with the underwritten private placement offering of subscription receipts (the "Offering").
- Valeura received $11.0 million in gross proceeds, which were released from escrow on February 24, 2017.
Statoil Transactions
Banarli Farm-in
- As announced on January 6, 2017 an affiliate of Valeura closed a transaction with Statoil Banarli Turkey B.V. ("Statoil"), a wholly-owned affiliate of Statoil ASA, for a farm-in agreement for the exploration of the deeper formations below approximately 2,500 metres on the Banarli licences targeting a potential basin-centered gas play (the "Banarli Farm-in"), following receipt of Turkish government approvals.
- Statoil has the option to earn a 50% participating interest in the deep formations on the Banarli licences by investing in an exploration program that includes payments and carried costs of at least US$36 million, including two deep exploration wells and 3D seismic.
- At closing of the Banarli Farm-in, Statoil paid Valeura US$6.0 million as a contribution to back costs incurred on the Banarli licences.
West Thrace Deep Rights Sale
- As announced on January 6, 2017, an affiliate of Valeura closed a second transaction with Statoil, to initially sell Valeura's current 40% participating interest in deep formations below approximately 2,500 metres on certain TBNG JV lands (the "West Thrace lands") for cash consideration of US$12 million (the "West Thrace Deep Rights Sale"), following receipt of Turkish government approvals.
- At closing of the West Thrace Deep Rights Sale, Statoil paid Valeura US$12.0 million.
- The West Thrace Deep Rights Sale provided a crucial source of non-dilutive funding for the TBNG Acquisition and further validates the potential for a deep basin-centered gas play on Valeura's lands.
Subsequent West Thrace Deep Rights Sale
- An affiliate of Valeura executed a sale and purchase agreement with Statoil on March 10, 2017 to sell additional 10% participating interest in the deep rights on the West Thrace lands for US$3 million (the "Subsequent West Thrace Deep Rights Sale"), as contemplated under terms of the West Thrace Deep Rights Deep Rights Sale agreement and contingent on closing the TBNG Acquisition.
- Closing of the Subsequent West Thrace Deep Rights Sale is subject to the Turkish government approvals for the associated transfer of the licence interests.
- Upon the closing of the West Thrace Deep Rights Sale and Subsequent West Thrace Deep Rights Sale, Valeura will retain a 31.5% participating interest and Statoil acquires a 50% participating interest in the deep formations on the West Thrace lands. Valeura will retain an 81.5% participating interest in the shallow formations on the West Thrace lands and an 81.5% participating interest in all formations on other TBNG JV lands (the "South Thrace lands"). Pinnacle Turkey Inc. ("PTI") will continue to hold an 18.5 % interest in all of the TBNG JV lands and all formations.
OPERATIONAL HIGHLIGHTS
- Net petroleum and natural gas sales in Turkey in Q4 2016 averaged 795 barrels of oil equivalent per day ("boe/d"), which were up 17% from Q3 2016 and down marginally from Q4 2015. Net sales in Q4 2016 included 4.7 million cubic feet per day ("MMcf/d") of natural gas and 12 barrels of oil per day ("bbl/d").
- Higher sales in Q4 2016 reflect a full quarter of production from the Bati Gurgen-2 well at Banarli and several workovers on the TBNG JV lands, partially offset by natural declines.
- Current net sales in Turkey are approximately 1,150 boe/d reflecting the acquisition of TBNG.
TBNG JV and Banarli Shallow Gas Program
- The Dogu Atakoy-3 well on the TBNG JV lands (Valeura 81.5% working interest) was spudded on January 24, 2017 and was drilled and cased to a depth of 1,303 metres. Based on the log interpretation, the well penetrated 40 metres of stacked Osmancik sands at an average porosity of 21%. The well has been on-stream for seven days and is currently producing at a restricted rate of approximately 1.0 MMcf/d (gross). The Dogu Atakoy-3 well satisfies the first of up to four commitment wells in 2017 under the licence terms on the West Thrace lands.
- Valeura is finalizing negotiations of a multi-well drilling rig contract for the planned 2017 shallow gas drilling program on the TBNG JV lands and Banarli licences, which is expected to commence in Q2 2017. A new slim-hole well design has been adopted for this program to reduce drilling times and costs.
- The General Directorate of Petroleum Affairs ("GDPA") has awarded two new production leases to the TBNG JV, F19-d3-1 and F19-c3-1 (Valeura 81.5% working interest). These leases comprise a gross area of 51,111 acres (41,655 net acres) and are part of the South Thrace lands.
- The TBNG JV has also relinquished two non-producing exploration licences N39-a1,a4 and N39-d1,d2 (Valeura 26% working interest) in the Gaziantep area of southeast Turkey due to limited prospectivity and a drilling commitment to hold the licences, and is a step consistent with the Corporation's strategy to focus on the Thrace Basin. These licences comprised a gross area of 152,111 acres (39,549 net acres). The Corporation does not hold any other licences or leases in southeast Turkey.
- Valeura currently holds interests in 528,504 gross acres in the Thrace Basin of northwest Turkey. Giving effect to the sale of a 50% participating interest to Statoil in the deep rights on the West Thrace lands, the Corporation would hold 432,295 net acres of shallow rights and 345,272 net acres of deep rights in the Thrace Basin.
Banarli Deep Exploration Program
- The Valeura/Statoil Banarli Deep Project Team has selected, after a thorough bid process, a deep capacity rig to drill the first 4,000 metre exploration well under the Phase 1 commitment of the Banarli Farm-in. Negotiation of the drilling rig contract is nearing completion. The selected drilling rig is currently located in Europe and will be transported to Turkey for a planned spud of the Yamalik-1 well in Q2 2017. A final AFE for the drilling and evaluation stages is being prepared, which will set Statoil's funding level for this particular stage of the well program. Under the Banarli Farm-in, Statoil will pay no less than US$10 million as a Phase 1 commitment to drill, evaluate, complete, frac and test the well. The actual amount funded for the well may be higher based on the actual agreed work program for the various stages.
- Bids are under review for the planned 3D seismic program under the Phase 2 commitment of the Banarli Farm-in. The acquisition stage is expected to commence in Q3 2017 and be completed before the end of 2017. Under the Banarli Farm-in, Statoil will pay no less than US$10 million for the acquisition and processing of the seismic.
- Valeura is the operator of the deep exploration program during the earning phase of the Banarli Farm-in.
FINANCIAL HIGHLIGHTS
- The Turkish Lira has continued to weaken in 2016, declining by 24% compared to the Canadian dollar over the course of 2016. This decline has negatively impacted Valeura's natural gas revenues which are priced in Turkish Lira, with some offset in reduced operating costs denominated in Turkish Lira. The Corporation is in the process of specifically assessing its exposure to the Turkish Lira and possibilities that may exist to mitigate this exposure.
- The average natural gas price realization in Turkey of $7.96 per thousand cubic feet ("Mcf") in Q4 2016 was down 15% and 20% from Q3 2016 and Q4 2015, respectively, due to a 10% reduction in the BOTAS Reference Price (in Turkish Lira) effective October 1, 2016 (as previously disclosed on November 10, 2016) and a further decline in the value of the Turkish Lira.
- The average operating netback of $33.43 per boe in Q4 2016 was down 14% from Q3 2016 due to lower natural gas price realizations, partially offset by lower unit operating costs, and down 25% from Q4 2015 due to lower natural gas price realizations and higher unit operating costs. (See discussion below regarding non-IFRS measures)
- The working capital surplus at December 31, 2016 was $3.8 million, including cash of $2.0 million.
- Funds flow from operations of $0.9 million in Q4 2016 was down 14% from Q3 2016 due to lower natural gas price realizations and higher general and administrative expenses, partially offset by higher sales volumes, lower unit operating costs and lower realized foreign exchange losses, and was down 43% from Q4 2015 due to lower sales volumes, lower natural gas price realizations and higher unit operating costs, partially offset by lower general and administrative expenses and lower realized foreign exchange losses. (See discussion below regarding non-IFRS measures)
- Net capital expenditures of $0.5 million in Q4 2016 were down 83% and 91% from Q3 2016 and Q4 2015, respectively, due to lower drilling expenditures.
- Additional financial and operating results are summarized in the Table 1 below.
Table 1 Financial and Operating Results Summary (1)
| (thousands of Canadian dollars, except share or per share amounts, and as otherwise stated) |
Three Months Ended December 31, 2016 |
Three Months Ended September 30, 2016 |
Year Ended December 31, 2016 |
Three Months Ended December 31, 2015 |
Year Ended December 31, 2015 |
|
| Financial |
||||||
| Petroleum and natural gas revenues |
3,508 |
3,510 |
16,155 |
4,425 |
21,543 |
|
| Funds flow from operations (1) |
915 |
1,066 |
6,048 |
1,600 |
10,185 |
|
| Net loss from operations |
(3,189) |
(1,263) |
(6,086) |
287 |
(562) |
|
| Capital expenditures |
536 |
3,080 |
9,535 |
6,100 |
13,192 |
|
| Net working capital surplus |
3,786 |
3,697 |
3,786 |
7,253 |
7,253 |
|
| Cash |
1,987 |
2,336 |
1,987 |
6,973 |
6,973 |
|
| Common shares outstanding |
||||||
| Basic |
58,519,321 |
58,519,321 |
58,519,321 |
57,906,135 |
57,906,135 |
|
| Diluted |
63,433,821 |
63,433,821 |
63,433,821 |
76,352,352 |
76,352,352 |
|
| Share trading |
||||||
| High |
1.15 |
1.25 |
1.44 |
0.66 |
0.71 |
|
| Low |
0.81 |
0.80 |
0.60 |
0.36 |
0.36 |
|
| Close |
0.95 |
0.85 |
0.95 |
0.66 |
0.66 |
|
| Operations |
||||||
| Production |
||||||
| Crude oil (bbl/d) |
12 |
10 |
9 |
8 |
8 |
|
| Natural Gas (Mcf/d) |
4,699 |
4,020 |
4,742 |
4,805 |
5,745 |
|
| boe/d (@ 6:1) |
795 |
680 |
799 |
809 |
966 |
|
| Average reference price |
||||||
| Brent ($ per bbl) |
65.17 |
59.75 |
57.67 |
58.16 |
66.88 |
|
| BOTAS Reference ($ per Mcf) (2) |
8.09 |
9.67 |
9.41 |
10.07 |
10.32 |
|
| Average realized price |
||||||
| Crude oil ($ per bbl) |
63.67 |
56.24 |
55.88 |
44.51 |
50.35 |
|
| Natural gas - Turkey ($ per Mcf) |
7.96 |
9.35 |
9.20 |
9.93 |
10.20 |
|
| Average Operating Netback |
||||||
| ($ per boe @ 6:1) (1) |
33.43 |
38.69 |
40.41 |
44.56 |
46.48 |
|
| Notes: |
|
| (1) |
The above table includes non-IFRS measures, which may not be comparable to other companies. Funds flow from operations is calculated as net income (loss) for the period adjusted for non-cash items in the statement of cash flows. Operating netback is calculated as petroleum and natural gas sales less royalties, production expenses and transportation costs. See MD&A for further discussion. |
| (2) |
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 Level-2 wholesale tariff is shown herein as a reference price. See the 2016 Annual Information Form for further discussion. |
2017 OUTLOOK
The Corporation is planning a capital expenditure program of $13 to 15 million (net) in 2017 focussed entirely on the shallow gas business. This level of spending is contingent on closing the Subsequent West Thrace Deep Rights Sale, and some stabilization of the Turkish Lira exchange rate and the BOTAS Reference Price (denominated in Turkish Lira). The capital program is expected to include drilling of up to seven wells (gross) in the shallow formations on the TBNG JV lands and Banarli licences, targeting 2017 exit rate sales of approximately 1,500 boe/d (net). This outlook is lower than earlier preliminary projections due to delays in completing the inter-linked transformational transactions, including the Banarli Farm-in, the West Thrace Deep Rights Sale, the TBNG Acquisition and the Offering, reflecting a longer than expected Turkish government approval process.
The Corporation also expects that the Banarli Farm-in program, fully funded by Statoil and operated by Valeura, will commence with the spudding of a deep exploration well in Q2 2017 under Phase 1 of the Banarli Farm-in and the start of the 3D seismic acquisition in Q3 2017 under Phase 2.
(See advisories below regarding outlook disclosures)
2016 YEAR-END CORPORATE RESERVES REPORT
The Corporation has completed its independent reserves evaluation as at December 31, 2016. 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 14, 2017 (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 2016 AIF filed on SEDAR. All of the Corporation's reserves are located in Turkey.
The D&M Reserves Report does not give effect to the TBNG Acquisition.
TBNG ACQUISITION PRO FORMA
On February 24, 2017, the Corporation announced the successful completion of the TBNG Acquisition. TBNG holds a 41.5% participating interest in the TBNG JV. Table 2 sets out pro forma combined reserves information for Valeura and TBNG as at December 31, 2016.
Table 2 Pro Forma Company Gross Reserves Volumes and Values Post TBNG Acquisition (1)(2)(3)
| PRO FORMA RESERVES AND NET PRESENT VALUE AT 10% BEFORE TAX YEAR ENDED DECEMBER 31, 2016 |
CHANGE % |
||||
| VALEURA(4) |
TBNG(5) |
PRO FORMA |
|||
| Reserves Volumes (Mboe) |
|||||
| Proved Reserves |
1,567 |
1,318 |
2,885 |
84 |
|
| Proved plus Probable Reserves |
4,704 |
4,198 |
8,902 |
89 |
|
| Proved plus Probable plus Possible Reserves |
7,230 |
6,315 |
13,545 |
87 |
|
| Reserves Value – NPV10 Before Tax ($MM) |
|||||
| Proved Reserves |
21.0 |
14.2 |
35.2 |
68 |
|
| Proved plus Probable Reserves |
61.8 |
47.9 |
109.7 |
78 |
|
| Proved plus Probable plus Possible Reserves |
103.8 |
80.5 |
184.3 |
78 |
|
| Notes: |
|
| (1) |
Valeura's reasonable expectation of how the TBNG Acquisition, had it occurred on or before the effective date of the information set out in Valeura's Statement of Reserves Data and Other Oil and Gas Information contained in the 2016 AIF, would have affected such information. |
| (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 0.74 for the year-end 2016 values. |
| (3) |
The forecast prices used in the calculations of the present value of future net revenue for year-end 2016 are based on the D&M December 31, 2016 forecast prices, which are contained in the 2016 AIF for the year ended December 31, 2016. |
| (4) |
D&M evaluated reserves as at December 31, 2016 on the Company's Banarli lands (100% working interest) and on the TBNG JV lands (40% working interest). |
| (5) |
TBNG's working interest in the TBNG JV lands is 41.5%. TBNG's reserves as of December 31, 2016 as presented were prepared internally (non-independent) by Valeura by making a mathematical adjustment of the Company's TBNG JV lands reserves that represents a 40% working interest to reflect TBNG's 41.5% working interest. |
2016 YEAR-END COMPANY RESERVES SUMMARY
Table 3 summarizes company reserves in Turkey and associated net present value discounted at 10% ("NPV10") before tax at December 31, 2016 and December 31, 2015 using forecast prices.
Table 3 Company Gross Reserves Volumes and Values (1)(2)(3)(4)
| RESERVES (Mboe) |
NET PRESENT VALUE AT 10% ($ MILLIONS - $MM) |
||||||
| 2016 |
2015 |
% CHANGE |
2016 |
2015 |
% CHANGE |
||
| Proved |
|||||||
| Developed producing |
470 |
509 |
-8 |
9.4 |
17.3 |
-46 |
|
| Developed non-producing |
405 |
513 |
-21 |
6.9 |
13.4 |
-49 |
|
| Undeveloped |
692 |
805 |
-14 |
4.7 |
10.4 |
-55 |
|
| Total Proved (1P) |
1,567 |
1,827 |
-14 |
21.0 |
41.1 |
-49 |
|
| Probable |
3,137 |
3,634 |
-14 |
40.8 |
75.9 |
-46 |
|
| Total Proved Plus Probable (2P) |
4,704 |
5,461 |
-14 |
61.8 |
117.0 |
-47 |
|
| Possible |
2,526 |
3,121 |
-19 |
42.0 |
71.6 |
-41 |
|
| Total Proved Plus Probable Plus Possible (3P) |
7,230 |
8,582 |
-16 |
103.8 |
188.6 |
-45 |
|
| Notes: |
|
| (1) |
See Oil and Gas Advisories and Reserve and Resource Definitions below. |
| (2) |
D&M's valuations for reserves in Turkey are prepared in US$ and have been converted for purposes of this illustration to Cdn$ assuming a $Cdn/$US exchange rate of 0.74 for the year-end 2016 values and 0.72 for the year-end 2015 values. |
| (3) |
The forecast prices used in the calculations of the present value of future net revenue for year-end 2016 are based on the D&M December 31, 2016 forecast prices, which are included in the 2016 AIF filed on SEDAR. The natural gas forecast prices (in US$/Mcf) are lower than 2015 reflecting a weaker Turkish Lira, reduced costs of imported gas and resulting lower BOTAS Reference Prices. |
| (4) |
Due to rounding, summations in the table may not add. |
The following tables and commentary summarize information contained in the D&M Reserves Report for Turkey. The D&M Reserves Report does not give effect to the TBNG Acquisition.
D&M evaluated reserves as at December 31, 2016 on the Company's Banarli licences (100% working interest) and TBNG JV lands (40% working interest). The reserves are primarily natural gas but small oil volumes are assigned to a number of wells.
The 2016 year-end reserves by principal product type are summarized in Table 4.
Table 4 2016 Year-end Company Gross Reserves Volumes by Principal Product Type (1)
| RESERVES CATEGORY |
LIGHT AND MEDIUM (Mbbl) |
CONVENTIONAL (Bcf) |
TOTAL OIL (Mboe) |
| Proved |
6 |
9.4 |
1,567 |
| Probable |
3 |
18.8 |
3,137 |
| Total Proved Plus Probable |
9 |
28.2 |
4,704 |
| Possible |
5 |
15.1 |
2,526 |
| Total Proved Plus Probable Plus Possible |
14 |
43.3 |
7,230 |
| Note: |
|
| (1) |
See Oil and Gas Advisories and Reserve Definitions below. |
The forecast oil and natural gas prices and cost escalation rates used in the D&M Reserves Report are shown in Table 5.
Table 5 Forecast Prices and Cost Escalation Rates (1)
| YEAR |
CONVENTIONAL NATURAL GAS |
LIGHT AND MEDIUM CRUDE OIL |
COST ESCALATION |
||
| BANARLI |
TBNG (US$/Mcf) |
BANARLI (US$/bbl) |
TBNG (US$/bbl) |
%/YEAR |
|
| 2017 |
5.99 |
6.11 |
42.15 |
42.15 |
0.0 |
| 2018 |
6.20 |
6.33 |
45.27 |
45.27 |
2.0 |
| 2019 |
6.43 |
6.57 |
48.50 |
48.50 |
2.0 |
| 2020 |
6.69 |
6.83 |
52.64 |
52.64 |
2.0 |
| 2021 |
6.96 |
7.11 |
55.31 |
55.31 |
2.0 |
| 2022 |
7.28 |
7.43 |
56.42 |
56.42 |
2.0 |
| 2023 |
7.61 |
7.77 |
58.39 |
58.39 |
2.0 |
| 2024 |
8.07 |
8.24 |
61.28 |
61.28 |
2.0 |
| 2025 |
8.55 |
8.73 |
64.26 |
64.26 |
2.0 |
| 2026 |
8.72 |
8.90 |
65.55 |
65.55 |
2.0 |
| 2027 |
8.89 |
9.08 |
66.86 |
66.86 |
2.0 |
| 2028 |
9.07 |
9.26 |
68.20 |
68.20 |
2.0 |
| 2029+ |
+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, 2016 forecast prices, which are included in the 2016 AIF filed on SEDAR. |
Table 6 sets forth a reconciliation of reserves changes in 2016.
Table 6 2016 Year-end Company Gross Reserves Reconciliation
| CHANGES |
1P (Mboe) |
2P (Mboe) |
|
| At December 31, 2015 |
1,827 |
5,461 |
|
| Technical Revisions |
32 |
-465 |
|
| Discoveries |
0 |
0 |
|
| Economic Factors |
0 |
0 |
|
| Production |
-292 |
-292 |
|
| At December 31, 2016 |
1,567 |
4,704 |
|
Table 7 sets forth the RLI for total proved and proved plus probable reserves based on the annualized Q4 production rates of 1,180 boe/d, 809 boe/d and 795 boe/d for the years 2014, 2015 and 2016, respectively.
Table 7 Reserve Life Index ("RLI") (1)(2)
| RLI (YEARS) |
2016 |
2015 |
2014 |
| Total Proved |
5.4 |
6.2 |
4.0 |
| Total Proved Plus Probable |
16.2 |
18.5 |
13.5 |
| 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 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 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 typically disclosed with reference to the number of days in which production is measured (e.g. IP30 refers to an initial on-stream average production rate measured over a 30-day period). Initial on-stream production rates are not necessarily indicative of long-term performance or ultimate recovery. To date, shallow gas conventional wells and fraced 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.
RESERVE 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 ("3P") reserves.
There is a 10% probability that the quantities actually recovered will equal or exceed the 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 and information (collectively referred to herein as "forward-looking information") including, but not limited to: the Corporation's 2017 work program, operational plans (drilling) on the TBNG JV lands and Banarli licences, expected capital expenditures, target production volumes, expected price realizations and expected operating netbacks; the final adjusted purchase price of TBNG having regard to that portion held in escrow; the ability to satisfy the conditions for closing the Subsequent West Thrace Deep Rights Sale, including securing Turkish government approvals for the transfer of various licence interests; the ability to close the Subsequent West Thrace Deep Rights Sale and the expected timing; the expected payment of US$3 million on the closing of the Subsequent West Thrace Deep Rights Sale; the key benefits of the TBNG Acquisition, the West Thrace Deep Rights Sale and the Subsequent West Thrace Deep Rights Sale; the prospectivity of the shallow formations on the TBNG JV lands and Banarli licences; the ability to fulfill the commitment program of spudding up to three additional shallow wells on the West Thrace lands by late June 2017; the availability of operating cash flow and the ability to finance development from existing cash, expected funds from closing of the Subsequent West Thrace Deep Rights Sale and operating cash flow; tying-in new wells and getting these on-stream; the timing, estimated costs and ability to fund the planned 2017 shallow gas program; the planned drilling and seismic program in 2017 for the Banarli Farm-in and the timing thereof; and the extent of over-pressure below approximately 2,500 metres across the Banarli licences and West Thrace lands and the potential for a basin-centered gas play. 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: political stability of the areas in which the Corporation is operating and completing transactions, and in particular the aftermath of the July 2016 failed coup attempt in Turkey; continued safety of operations and ability to proceed in a timely manner; the ability to close the Subsequent West Thrace Deep Rights Sale; continued operations of and approvals forthcoming from the Turkish government in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the prospectivity of the TBNG JV lands and Banarli licences, including the deep potential; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licences and leases; 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, fracing and other specialized oilfield equipment and service providers, changes in 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: the risks of delay or not obtaining Turkish government approvals in a timely manner for the transfer of licence interests in light of the July 2016 failed coup attempt in Turkey and its aftermath, and the upcoming referendum on constitutional change, or satisfying other conditions for closing the Subsequent West Thrace Deep Rights Sale; failure to realize the key benefits of the TBNG Acquisition, the West Thrace Deep Rights Sale and the Subsequent West Thrace Deep Rights Sale; the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the availability of drilling rigs and associated equipment on the contemplated timelines for shallow drilling and deep drilling; 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; political stability in Turkey, including potential changes in Turkey's constitution, political leaders or parties or a resurgence of a coup or other political turmoil; the uncertainty regarding government and other approvals; potential changes in laws and regulations; risks associated with weather delays and natural disasters; the risk associated with international activity; and, the uncertainty regarding the ability to fulfill the drilling commitments on the West Thrace lands. 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 2016 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, including, but not limited to, the expected acquisition metrics of the TBNG Acquisition. 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., (403) 930-1150, [email protected]; Steve Bjornson, CFO, Valeura Energy Inc., (403) 930-1151, [email protected]; www.valeuraenergy.com
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