CALGARY, March 11, 2014 /CNW/ - Valeura Energy Inc. ("Valeura" or the "Corporation") (TSX: VLE) is pleased to report highlights of its unaudited financial
and operating results for the three month period ended December 31,
2013, audited results for the year ended December 31, 2013, year-end
2013 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 2013 Annual Information Form ("2013 AIF"), have been filed on SEDAR at www.sedar.com and posted on the Corporation's website at www.valeuraenergy.com.
Q4 2013 RESULTS AT A GLANCE
-
Net sales 1,191 boe/d, up 18% from Q3 2013
-
Funds flow from operations $3.8 million, up 24% from Q3 2013
-
Operating netback $43.25 per boe
-
1P reserves 1.8 MMboe and 2P reserves 5.8 MMboe at year-end 2013, up 55%
and 16%, respectively, from year-end 2012
-
Replaced 280% of corporate production at the 1P level and 326% of
production at the 2P level in 2013
-
1P reserves value $46 MM or $0.80 per share; 2P reserves value $130 MM
or $2.24 per share (NPV10 before tax)
-
9 additional re-entry fracs completed in new Mezardere slope fan play
-
Drilled and fracked a third horizontal tight gas well with IP30 of 2.0
MMcf/d (gross)
(See below for definitions and advisories)
OPERATIONAL HIGHLIGHTS
-
Net corporate petroleum and natural gas sales in the fourth quarter of
2013 averaged 1,191 barrels of oil equivalent per day ("boe/d"), which was 18% higher than sales in the third quarter of 2013. Net
sales in Turkey in the fourth quarter of 2013 averaged 1,149 boe/d,
including 6.8 million cubic feet per day ("MMcf/d") of natural gas and 14 barrels of oil per day ("bopd"). Net sales in Canada in the fourth quarter of 2013 averaged 42 boe/d.
-
Net corporate petroleum and natural gas sales to date in the first
quarter of 2014 have averaged approximately 1,300 boe/d reflecting
continued growth in gas production from the Thrace Basin in Turkey.
Thrace Basin - TBNG JV (Valeura 40%)
-
Completed 232 square kilometres of new 3D seismic in the Osmanli area at
a cost of $2.3 million (net) on joint venture lands acquired from
Thrace Basin Natural Gas (Turkiye) Corporation ("TBNG") and Pinnacle Turkey Inc. ("PTI") (the "TBNG JV") (Valeura 40%). The Osmanli area is located to the north and west of
the Tekirdag area, where the bulk of the natural gas development has
occurred on the TBNG JV lands. The new seismic is expected to provide
additional drilling opportunities in both the target Osmancik shallow
gas reservoirs and Mezardere and Teslimkoy tight gas reservoirs.
-
Drilled and fracked the third horizontal well BTD-5H in the horizontal
drilling pilot in the Tekirdag area. The BTD-5H well was drilled to a
vertical depth of 975 metres into the Teslimkoy Formation with a
horizontal section of 403 metres and was completed with a 3-stage frac
in late December 2013. Over the first 30 days after tie-in, the BTD-5H
well flowed at an average restricted rate of 2.0 MMcf/d (gross) ("IP30") through a 30/64" choke. The cost to drill, frac and tie-in the BTD-5H
well was under budget at approximately $2.1 million (gross). (Note that
the initial production rates stated throughout this press release are
not necessarily indicative of long term performance or ultimate
recovery).
-
Completed nine well re-entry fracs in the fourth quarter of 2013 in the
Mezardere Formation, increasing the 2013 well total to 17. The average
per well IP30 on 13 wells with 30 days of on-stream history is
approximately 1.1 MMcf/d.
-
In a subsequent development in the first quarter of 2014, drilled two
additional horizontal wells BTD-2H and TDR-11H into the Mezardere
Formation to follow-up on the successful 2013 re-entry frac program in
this formation. The BTD-2H well was fracked on March 4, 2014 and is
tied-in and flowing at a restricted rate of approximately 1.8 MMcf/d
(gross) through a 28/64" choke. The BTD-2H well is continuing to clean
up with only 25% of the completion load fluid recovered to date. It is
expected that the TDR-11H well will be completed with a 10-stage frac
before the end of March.
Thrace Basin - Banarli Exploration Licence (Valeura 100%)
-
Valeura is continuing to seek a joint venture partner to participate in
funding an exploration program on the 100% owned and operated Banarli
Exploration Licence 5104. The Company has recently engaged Moyes & Co.,
an internationally active acquisition and divestment firm, to assist in
the farm-out process.
Anatolian Basin
-
Valeura sold its 27.5% interest in two Karakilise Licences 2674 and 2677
in the Anatolian Basin, which included two marginal oil wells producing
in aggregate less than 10 bopd (net). Both licences were near expiry at
the end of their 11-year term, requiring applications for production
leases and relinquishment of the residual exploration areas by May
2014. The Corporation assessed that there was limited upside potential
in retaining these licences.
FINANCIAL HIGHLIGHTS
-
Funds flow from operations of $3.8 million in the fourth quarter of 2013
was up 24% from the third quarter of 2013 due primarily to higher sales
volumes, partially offset by slightly lower natural gas price
realizations in Turkey. Funds flow from operations in the fourth
quarter of 2013 was up 40% from the same period in 2012 due to higher
sales volumes and higher natural gas price realizations in Turkey.
Funds flow from operations in 2013 of $10.2 million was 14% lower than
2012 due primarily to lower volumes, partially offset by higher natural
gas price realizations in Turkey. (See discussion below regarding
non-IFRS measures).
-
Capital expenditures of $5.8 million in the fourth quarter of 2013 were
down 32% from the third quarter of 2013 and down 7% from the same
period in 2012 reflecting lower drilling expenditures. Capital
expenditures of $27.0 million in 2013 were also down 14% from 2012
reflecting lower drilling expenditures.
-
The Corporation's gas sales are priced in Turkish Lira linked to
reference prices posted by Boru Hatlari ile Petrol Tasima Anonim
Sirketi ("BOTAS"), which buys most of the imported gas in Turkey for re-sale to
distribution companies. Natural gas price realizations in Turkey in the
fourth quarter of 2013 averaged $9.93 per Mcf, which were down 2% from
the third quarter of 2013 due primarily to a weakening of the Turkish
Lira ("TL"), and up 2% from the same period in 2012 due to improvements in gas
sales contract terms, partially offset by the weakening of the TL. The
TL continued to weaken in early 2014, which reduced the average natural
gas price realization in Turkey to $9.57 per Mcf in January 2014 at an
exchange rate of $1.00 = 2.03 TL.
-
The corporate average operating netback of $43.25 per boe in the fourth
quarter of 2013 was down 4% from the third quarter of 2013 due
primarily to lower natural gas price realisations and higher unit
operating costs, and up 11% from the same period in 2012 due primarily
to lower unit operating costs and higher natural gas price
realisations. (See discussion below regarding non-IFRS measures).
-
As at December 31, 2013, the Corporation had a working capital surplus
of $6.8 million, including cash and cash equivalents of $6.5 million.
This compares to a working capital surplus of $24.2 million as at
December 31, 2012.
-
Additional financial and operating results are summarized in the Table 1
below.
Table 1 Financial Results Summary
(thousands of Canadian dollars, except
share and per share amounts)
|
Three Months
Ended
December 31,
2013
|
Three Months
Ended
September 30,
2013
|
Year
Ended
December 31,
2013
|
Three Months
Ended
December 31,
2012
|
Year
Ended
December 31,
2012
|
Financial
(CDN$ except share and per share amounts)
|
|
|
|
|
|
Petroleum and natural gas revenues
|
6,556
|
5,749
|
22,050
|
5,409
|
24,942
|
Funds flow from operations (1)
|
3,789
|
3,067
|
10,218
|
2,700
|
11,816
|
Net loss
|
(9,888)
|
(4,632)
|
(17,566)
|
(12,110)
|
(15,905)
|
Capital expenditures
|
5,780
|
8,445
|
26,973
|
6,231
|
31,255
|
Net working capital surplus
|
6,834
|
9,029
|
6,834
|
24,257
|
24,257
|
Cash and cash equivalents
|
6,511
|
9,850
|
6,511
|
29,031
|
29,031
|
Common shares outstanding
Basic
Diluted
|
57,906,135
75,819,352
|
57,906,135
78,993,352
|
57,906,135
75,819,352
|
57,906,135
77,351,102
|
57,906,135
77,351,102
|
Share trading
High
Low
Close
|
0.43
0.27
0.30
|
0.50
0.31
0.42
|
1.15
0.27
0.30
|
1.27
0.70
0.92
|
2.89
0.70
0.92
|
Operations
|
|
|
|
|
|
Sales
|
|
|
|
|
|
Crude oil & NGLs (bbl/d)
|
44
|
48
|
49
|
61
|
63
|
Natural Gas (Mcf/d)
|
6,883
|
5,778
|
5,589
|
5,682
|
7,206
|
BOE/d (@ 6:1) (2)
|
1,191
|
1,011
|
980
|
1,008
|
1,264
|
Average reference price
Edmonton light ($ per bbl)
AECO ($ per Mcf)
BOTAS Reference ($ per Mcf) (3)
|
86.28
3.69
10.44
|
104.69
2.30
10.63
|
92.92
3.18
10.89
|
83.99
3.21
11.12
|
86.10
2.36
9.97
|
Average realized price
Crude oil ($ per bbl)
Natural gas - Turkey ($ per Mcf)
Natural gas - consolidated ($ per Mcf)
|
78.23
9.93
9.86
|
94.75
10.13
10.03
|
82.05
10.23
10.11
|
77.98
9.70
9.54
|
79.75
8.90
8.77
|
Average Operating Netback
($ per BOE @ 6:1) (1) (2)
|
43.25
|
45.07
|
42.47
|
38.90
|
37.40
|
Notes:
|
(1)
|
The above table includes non-IFRS measures, which may not be comparable
to other companies. Funds flow from operations is calculated as net
loss for the period adjusted for non-cash items in the statement of
cash flows. Operating netback is calculated as petroleum and natural
gas sales less royalties, production expenses and transportation costs.
See MD&A for further discussion.
|
(2)
|
BOEs may be misleading, particularly if used in isolation. A BOE
conversion ratio of 6.0 Mcf:1.0 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
necessarily represent a value equivalency at the well head.
|
(3)
|
BOTAS owns and operates the national crude oil and natural gas pipeline
grids in Turkey. BOTAS regularly posts prices and its Industrial
Interruptible Tariff benchmark is shown herein as a reference price.
See the 2013 AIF for further discussion.
|
RESERVES
The Corporation has completed its independent reserves evaluations for
Turkey and Canada as at December 31, 2013. These evaluations were
conducted by DeGolyer and MacNaughton ("D&M") of Dallas, Texas for the Corporation's properties in Turkey in its
report dated March 11, 2014 (the "D&M Reserves Report") and GLJ Petroleum Consultants Ltd. ("GLJ") of Calgary, Alberta for the Canadian properties in its report dated
February 26, 2014 (the "GLJ Report"). These evaluations were prepared using guidelines outlined in the
Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and are 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 2013 AIF filed on SEDAR.
Total Company Reserves Summary
The following tables 2 and 3 summarize and compare total company
reserves in Turkey and Canada and associated net present value
discounted at 10% ("NPV10") before tax at December 31, 2013 and December 31, 2012 using forecast
prices.
Table 2 Company Gross Reserves Volumes (Mboe) (1)
RESERVES CATEGORY
|
2013
|
2012
|
%
CHANGE
|
TURKEY
|
CANADA
|
TOTAL
|
TURKEY
|
CANADA
|
TOTAL
|
Proved
|
|
|
|
|
|
|
|
Developed producing
|
746
|
55
|
801
|
328
|
65
|
393
|
+104
|
Developed non-producing
|
318
|
80
|
398
|
304
|
78
|
382
|
+4
|
Undeveloped
|
584
|
-
|
584
|
374
|
-
|
374
|
+56
|
Total Proved (1P)
|
1,648
|
135
|
1,783
|
1,006
|
143
|
1,149
|
+55
|
Probable
|
3,680
|
323
|
4,003
|
3,480
|
358
|
3,838
|
+4
|
Total Proved Plus Probable (2P)
|
5,328
|
458
|
5,786
|
4,486
|
501
|
4,987
|
+16
|
Possible (2)
|
4,971
|
-
|
4,971
|
4,705
|
-
|
4,705
|
+6
|
Total Proved Plus Probable Plus Possible (3P) (2)
|
10,299
|
458
|
10,757
|
9,191
|
501
|
9,692
|
+11
|
Notes:
|
(1)
|
See Oil and Gas Advisories and Reserves Classifications below.
|
(2)
|
An estimate of possible reserves associated with the Canadian properties
has not been prepared.
|
Table 3 Net Present Value at 10% Before Tax ($ Millions - $MM) (1)(2)(3)(4)
RESERVES CATEGORY
|
2013
|
2012
|
%
CHANGE
|
TURKEY
|
CANADA
|
TOTAL
|
TURKEY
|
CANADA
|
TOTAL
|
Proved
|
|
|
|
|
|
|
|
Developed producing
|
30.0
|
1.1
|
31.1
|
8.0
|
1.1
|
9.1
|
+241
|
Developed non-producing
|
8.8
|
0.4
|
9.2
|
8.4
|
0.4
|
8.8
|
+5
|
Undeveloped
|
6.3
|
-
|
6.3
|
1.0
|
-
|
1.0
|
+530
|
Total Proved (1P)
|
45.1
|
1.5
|
46.5
|
17.5
|
1.5
|
19.0
|
+144
|
Probable
|
80.1
|
3.2
|
83.3
|
70.3
|
3.8
|
74.1
|
+123
|
Total Proved Plus Probable (2P)
|
125.2
|
4.7
|
129.9
|
87.7
|
5.3
|
93.0
|
+39
|
Possible (5)
|
117.1
|
-
|
117.1
|
105.1
|
-
|
105.1
|
+11
|
Total Proved Plus Probable Plus Possible (3P)
|
242.3
|
4.7
|
247.0
|
192.8
|
5.3
|
198.1
|
+24
|
Notes:
|
(1)
|
See Oil and Gas Advisories and Reserves Classifications below.
|
(2)
|
D&M's valuations for reserves in Turkey are prepared in US$ and have
been converted for purposes of this illustration to Cdn$ assuming a
$Cdn/$US exchange rate of 0.94 for the year-end 2013 values and 1.00
for the year-end 2012 values.
|
(3)
|
The forecast prices used in the calculations of the present value of
future net revenue for year-end 2013 are based on the D&M December 31,
2013 and GLJ January 1, 2014 forecast prices, which are included in the
2013 AIF filed on SEDAR.
|
(4)
|
Due to rounding, summations in the table may not add.
|
(5)
|
An estimate of possible reserves associated with the Canadian properties
has not been prepared.
|
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, 2013 on the TBNG JV lands (40%
working interest), the Edirne Licence in the Thrace Basin (35% working
interest) and the Gaziantep Licence 4076 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 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. The results are
summarized in Table 4 below.
Table 4 Turkey 2013 Year-end Company Gross Reserves Volumes and Values (1)(2)
RESERVES
CATEGORY
|
LIGHT/MEDIUM
OIL
(Mbbl)
|
NATURAL GAS
(Bcf)
|
TOTAL OIL
EQUIVALENT
(Mboe)
|
NPV10 BEFORE TAX
(US$MM)
|
Proved
|
86
|
9.4
|
1,648
|
42.4
|
Probable
|
50
|
21.8
|
3,680
|
75.3
|
Total proved plus probable
|
136
|
31.2
|
5,328
|
117.7
|
Possible
|
78
|
29.4
|
4,971
|
110.1
|
Total proved, probable and possible
|
214
|
60.5
|
10,299
|
227.8
|
Notes:
|
(1)
|
See Oil and Gas Advisories and Reserves Classifications below.
|
(2)
|
The forecast prices used in the calculation of the present value of
future net revenue are based on the D&M December 31, 2013 forecast
prices, which are included in the 2013 AIF filed on SEDAR.
|
Contingent Resources
The Corporation has not updated the contingent resources assessment for
the Thrace Basin carried out by D&M as at December 31, 2012, which was
summarized in Valeura's 2012 Annual Information Form. Any decision to
update D&M's contingent resources assessment will be dependent on
further results from horizontal drilling on the TBNG JV lands and
potential exploration drilling on the Banarli Licence 5104 in 2014.
Canada
The following table and commentary summarize information contained in
the GLJ Reserves Report for Canada.
GLJ evaluated the Corporation's reserves in Canada, which consist of
light and medium oil, heavy oil, natural gas liquids and natural gas as
summarized in Table 5 below.
Table 5 Canada 2013 Year-end Company Gross Reserves Volumes and Values (1)(2)
RESERVES
CATEGORY
|
OIL (3)
(Mbbl)
|
NATURAL GAS
(Bcf)
|
NATURAL GAS
LIQUIDS
(Mbbl)
|
TOTAL OIL
EQUIVALENT
(Mboe)
|
NPV10 BEFORE TAX
($MM)
|
Proved
|
63
|
0.4
|
14
|
135
|
1.5
|
Probable
|
113
|
0.9
|
54
|
323
|
3.2
|
Total proved plus probable
|
176
|
1.3
|
68
|
458
|
4.7
|
Notes:
|
(1)
|
See Oil and Gas Advisories and Reserves Classifications below.
|
(2)
|
The forecast prices used in the calculation of the present value of
future net revenue are based on the GLJ January 1, 2014 forecast
prices, which are included in the 2013 AIF filed on SEDAR.
|
(3)
|
Includes light, medium and heavy oil.
|
OUTLOOK
The Corporation expects to execute a capital expenditure budget of up to
$14 to 17 million (net) in Turkey in 2014, focused on natural gas
development in the Thrace Basin, and contingent on the level of
operating cash flow. The work program and budget aims to achieve the
following key objectives in 2014, as outlined in the Corporation's
January 9, 2014 operational update and 2014 guidance press release:
-
Offset natural declines and achieve 5 to 10% annualized production
growth from trailing quarter rates with a natural gas development
program on the TBNG JV lands funded by available cash and operating
cash flow, focused primarily on exploiting tight gas reservoirs with
horizontal and vertical wells completed with multi-stage fracs
-
Expand the tight gas development area on the TBNG JV lands from the
Tekirdag area to other areas in Osmanli and Hayrabolu, which are also
covered with 3D seismic
-
Test for the presence of a basin-centred gas accumulation on Valeura's
100% owned Banarli Licence, subject to obtaining a partner or other
financing
The planned work program on the TBNG JV lands in 2014 includes up to 12
horizontal and vertical wells (gross) utilizing a single drilling rig.
Of this total, up to eight new drill wells with multi-stage frac
completions are planned targeting tight gas reservoirs in the Mezardere
and Teslimkoy Formations and up to four wells targeting conventional
shallow gas reservoirs. Up to an additional 13 well re-entry fracs
(gross) are also planned, primarily targeting the Mezardere Formation.
To date in 2014, two horizontal wells BTD-2H and TDR-11H have been
drilled in the Mezardere Formation. An additional 25 potential
horizontal drilling locations in the Mezardere Formation have been
identified within the Tekirdag field alone.
A key focus in 2014 will be to further improve capital efficiency,
particularly through the reduction of drilling costs, building on
analogue experience in North America and recent drilling efficiency
improvements achieved by the operator on the TBNG JV lands. The
Corporation is targeting an average cost in 2014 of $3.0 million
(gross) to drill a typical horizontal well to a vertical depth of 1,000
metres with an 800 metre horizontal leg and to complete it with a
10-stage frac. These horizontal wells are expected to be longer with
more frac stages compared to the initial five wells drilled in 2013 and
early 2014. The cost to drill a vertical well to a depth of 1,400
metres and to complete it with a 4-stage frac is targeted at $1.9
million (gross). The typical cost for well re-entry frac is estimated
at $0.5 million (gross).
Good progress is already being made on drilling efficiency and cost,
which provides increasing confidence that the target costs described
above can be achieved or bettered in 2014. In particular, the BTD-5H
horizontal well was drilled to a measured length of 1,519 metres in 15
days and fracked (3-stage) for a total cost of $2.1 million (gross) in
late December 2013. The next horizontal well BTD-2H well was drilled to
a measured length of 1,246 metres in 13 days and fracked (8-stage) for
a total cost of $2.1 million (gross) in early March 2014. Similar
drilling times of 11 days were achieved in the most recent horizontal
well TDR-11H, which was drilled to a measured length of 1,291 metres
and rig released in early March, and is expected to be fracked later
this month.
ADOPTION OF AMENDED AND RESTATED BY-LAWS
Valeura is also pleased to report that the board of directors has
approved the adoption of an amended and restated by-law no. 1 (the "Amended and Restated By-Laws") which, among other things, incorporates advance notice provisions
with respect to director nominations. The advance notice provisions set
a deadline by which shareholders must notify the Corporation in writing
of an intention to nominate directors prior to any meeting of
shareholders at which directors are to be elected and set forth the
information that the shareholder must include in the notice for it to
be valid. The Amended and Restated By-Laws, including the advance
notice provisions, are effective immediately and will be subject to
shareholder approval at the annual and special meeting of shareholders
to be held on May 15, 2014. The full text of the Amended and Restated
By-Laws is available under Valeura's profile on SEDAR at www.sedar.com.
ABOUT THE CORPORATION
Valeura Energy Inc. is a Canada-based public company currently engaged
in the exploration, development and production of petroleum and natural
gas in Turkey and Western Canada.
OIL AND GAS ADVISORIES AND RESERVES CLASSIFICATIONS
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:1.0 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the well head.
The initial production rates for wells stated herein are not necessarily
indicative of long term performance or ultimate recovery. To date,
shallow gas conventional wells and fracked unconventional tight gas
wells have exhibited relatively high decline rates at more than 50% and
75%, respectively, in their first year of production.
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 future net revenue estimates provided herein do not represent fair
market value.
Reserves Classifications
"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" 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 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 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 2014 work program and budget, operational plans
and costs (seismic, drilling and fracking) for the tight gas and
shallow gas development programs in the Thrace Basin; the ability to
reduce costs, achieve capital efficiencies, increase production and the
associated corporate sales outlook; the availability of operating cash
flow and the ability to finance development; the continued drilling of
horizontal wells to be completed with multi-stage fracs and the
expected attributes of those wells and impact thereof; the future
development program in the Thrace Basin; the ability to expand the
development area on the TBNG JV lands; the potential for additional
re-completions and a follow-on development program in the Mezardere
Formation; any decision to update D&M's contingent resources
assessment; the timing, estimated costs and ability to fund each of the
foregoing; the plans to attract a joint venture partner and drill an
exploration well on the Banarli Licence and the costs, timing, funding
and potential upside thereof; and the ability to obtain shareholder
approval of the Amended and Restated By-Laws. Forward-looking
information typically contains statements with words such as
"anticipate", "estimate", "expect", "target", "potential", "could",
"should", "would" or similar words suggesting future outcomes. The
Corporation cautions readers and prospective investors in the
Corporation's securities to not place undue reliance on forward-looking
information, as by its nature, it is based on current expectations
regarding future events that involve a number of assumptions, inherent
risks and uncertainties, which could cause actual results to differ
materially from those anticipated by the Corporation.
Forward-looking information is based on management's current
expectations and assumptions regarding, among other things: continued
political stability of the areas in which the Corporation is operating
and completing transactions; continued operations of and approvals
forthcoming from the General Directorate of Petroleum Affairs of the
Republic of Turkey in a manner consistent with past conduct; results of
future seismic programs; future drilling, fracking and re-completion
activity, including the extent and pace of tight gas delineation and
development drilling in the Tekirdag area and the funding thereof; the
prospectivity of the Osmanli and Hayrabolu areas; the ability to manage
water production; 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, including the
spudding deadline under the Banarli Licence 5104; the ability to
attract partners and negotiate farm-in arrangements, in particular on
the Banarli Licence 5104; future sources of funding; future economic
conditions; future currency and exchange rates; and, the Corporation's
continued ability to obtain and retain qualified staff and equipment in
a timely and cost efficient manner. In addition, the Corporation's 2014
work program and budget are based upon the current work programs
proposed by partners and associated exploration, development and
marketing plans and anticipated costs and sales prices, which are
subject to change based on, among other things, the actual results of
drilling and related activity, availability of fracking and other
specialized oilfield equipment and service providers, and unexpected
delays and changes in market conditions. Although the Corporation
believes the expectations and assumptions reflected in such
forward-looking information are reasonable, they may prove to be
incorrect.
Forward-looking information involves significant known and unknown risks
and uncertainties. Exploration, appraisal, and development of oil and
natural gas reserves are speculative activities and involve a
significant degree of risk. A number of factors could cause actual
results to differ materially from those anticipated by the Corporation
including, but not limited to: risks associated with the oil and gas
industry (e.g. operational risks in exploration, inherent uncertainties
in interpreting geological data, and changes in plans with respect to
exploration or capital expenditures, the uncertainty of estimates and
projections in relation to costs and expenses, and health, safety, and
environmental risks); uncertainty regarding the sustainability of
initial production rates and decline rates thereafter; uncertainty
regarding the ability to address technical drilling challenges and
manage water production; uncertainty regarding the state of capital
markets and the availability of future financings; the risk of being
unable to secure farm-in partners; the risk of being unable to meet
drilling deadlines and the requirements under licences and leases
(including the Banarli Licence 5104); uncertainty regarding 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 (particularly in the southeastern part of
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 pricing (in
Turkish Lira); the risk of fluctuations in foreign exchange rates,
particularly the Turkish Lira, which has weakened in the past year; the
uncertainty associated with negotiating with third parties in countries
other than Canada; the risk of partners having different views on work
programs and potential disputes among partners and service providers;
the uncertainty regarding government and other approvals; potential
changes in laws and regulations; risks associated with weather delays
and natural disasters; and, the risk associated with international
activity. The forward-looking information included in this news release
is expressly qualified in its entirety by this cautionary statement.
The forward-looking information included herein is made as of the date
hereof and Valeura assumes no obligation to update or revise any
forward-looking information to reflect new events or circumstances,
except as required by law. See the 2013 AIF for a detailed discussion
of the risk factors.
Additional information relating to Valeura is also available on SEDAR at
www.sedar.com
Neither the Toronto Stock Exchange nor its Regulation Services Provider
(as that term is defined in the policies of the Toronto Stock Exchange)
accepts responsibility for the adequacy or accuracy of this news
release.
SOURCE Valeura Energy Inc.