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| 8-K - FORM 8-K - TRANSATLANTIC PETROLEUM LTD. | d546468d8k.htm |
 SunTrust
Robinson Humphrey “Play-by-Play”
Oil & Gas Conference
May 30, 2013
Exhibit 99.1 |
 FORWARD
LOOKING STATEMENTS 2
Outlooks, projections, estimates, targets and business plans in this presentation or
any related subsequent discussions are forward-looking statements. Actual
future results, including TransAtlantic Petroleum Ltd.’s own production growth and mix; financial results; the amount and mix of capital expenditures;
resource additions and recoveries; finding and development costs; project and drilling
plans, timing, costs, and capacities; revenue enhancements and cost
efficiencies; industry margins; margin enhancements and integration benefits; and the
impact of technology could differ materially due to a number of factors. These
include market prices for natural gas, natural gas liquids and oil products; estimates of reserves and economic assumptions; the ability to produce and
transport natural gas, natural gas liquids and oil; the results of exploration and
development drilling and related activities; economic conditions in the countries
and provinces in which we carry on business, especially economic slowdowns; actions by
governmental authorities, receipt of required approvals, increases in taxes,
legislative and regulatory initiatives relating to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of
contracts; political uncertainty, including actions by insurgent groups or other
conflict; the negotiation and closing of material contracts; shortages of drilling
rigs, equipment or oilfield services; and other factors discussed here and under the
heading “Risk Factors" in our Annual Report on Form 10-K for the year
ended December 31, 2012 and our Quarterly Report on Form 10-Q for the three months
ended March 31, 2013, which are available on our website at
www.transatlanticpetroleum.com and www.sec.gov. See also TransAtlantic’s audited
financial statements and the accompanying management discussion and analysis.
Forward-looking statements are based on management’s knowledge and reasonable expectations on the date hereof, and we assume no duty
to update these statements as of any future date. The
information set forth in this presentation does not constitute an offer, solicitation or recommendation to sell or an offer to buy any securities of the
Company. The information published herein is provided for informational purposes only.
The Company makes no representation that the information and opinions expressed
herein are accurate, complete or current. The information contained herein is current as of the date hereof, but may become outdated or
subsequently may change. Nothing contained herein constitutes financial, legal, tax, or
other advice.
The SEC has generally permitted oil and gas companies, in their filings with the SEC,
to disclose only proved reserves that a company has demonstrated by actual
production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We may use the
terms “estimated ultimate recovery,” “EUR,” “probable,”
“possible,” and “non-proven” reserves, “prospective resources” or “upside” or other descriptions of
volumes of resources or reserves potentially recoverable through additional drilling or
recovery techniques that the SEC’s guidelines may prohibit us from
including in filings with the SEC. These estimates are by their nature more speculative
than estimates of proved reserves and accordingly are subject to substantially
greater risk of actually being realized by the Company. There is no certainty that any portion of estimated prospective resources will be
discovered. If discovered, there is no certainty that it will be commercially viable to
produce any portion of the estimated prospective resources.
Boe (barrel of oil equivalent) is derived by converting natural gas to oil in the ratio
of six thousand cubic feet (Mcf) of natural gas to one barrel (bbl) of oil. Boe
may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1
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. |
 COMPANY
OVERVIEW TransAtlantic Petroleum Ltd. is an international energy company engaged in
the acquisition, development,
exploration
and
production
of
crude
oil
and
natural
gas
in
Turkey
and
Bulgaria.
3
NYSE-MKT:
Toronto:
TAT
TNP
Share Price
(1)
:
$0.84
Market Cap
(1)
:
$310 million
Enterprise Value
(1)
:
$330 million
Proved Reserves
(2)
:
11.6 MMboe
SEC PV-10
(3)
:
$511.0 million
(1)
Market data as of 5/24/2013.
(2)
DeGoyler and MacNaughton reserves as of 12/31/2012 based on $108.30/barrel and
$8.94/Mcf. (3)
Please see reconciliation of PV-10 to standardized measure at end of
presentation. Executive Management
Chairman & CEO:
N. Malone Mitchell, 3rd
President:
Ian J. Delahunty
VP, CFO:
Wil F. Saqueton
VP, Legal:
Jeffrey S. Mecom |
 COMPANY
OBJECTIVES Work in countries with favorable fiscal terms where
we earn world market prices
•
Türkiye (Turkey)
•
Bulgaria
4
Acquire assets with known production or verifiable
“show”
wells
•
Utilize technology to enhance or commercialize
•
Earn early cash flow from sales
•
Evaluate, plan & monitor from Dallas, Texas headquarters
–
Seismic, horizontal, and stimulation
–
12.5% Royalty, no production tax
–
Oil: Brent less $7-10, Natural gas: +/-
$10/mcf
–
Currently imports nearly all oil and natural gas
–
2.5% Royalty (until 1.5x payout), no production tax
–
Natural gas: +/-
$9/mcf
–
Currently imports nearly all oil and natural gas |
 2013 PLAN
OF ACTION 5
Financial Overview
•
$130 million capital budget
•
Operate within cash flow, cash on hand and credit
availability
•
Accelerate with consummation of a joint venture
Southeastern Türkiye
•
Drill horizontal wells to increase productivity
•
3D seismic of Molla blocks
•
Expand 2012 discoveries (Goksu, Bahar, and Alibey)
•
Resume development at Selmo with horizontal wells
•
Arar acquisition of more than 150,000 acres in Molla
area, 100% working interest and operatorship
Northwestern Türkiye
•
Tekirdag development project: low risk gas
production growth, 2 well horizontal trial
•
Hayrabolu: exploration and delineation wells,
overpressure below 1,500 meters
•
Final exploitation of Edirne blocks (NW Thrace)
•
Limited development within TPAO (Turkish
Petroleum) joint blocks
•
3D on Osmanli structure near Thrace area “kitchen”
Bulgaria
•
Expect to resume activity 3Q 2013
•
Reviewing other prospects outside Türkiye |
 CURRENT
OPERATIONS 6
125 miles
200 kilometers |
 1Q 2013
RESULTS 7
Net sales (Boed)
4,144
Realized oil price (per bbl)
$103.00
Realized natural gas price (per mcf)
$10.12
Net income ($MM)
$3.0
Adjusted EBITDAX ($MM)
$19.5
Cash and cash equivalents ($MM)
$19.4
Debt ($MM)
$39.8
Note: Results are for the three months ending March 31, 2013. Realized prices are
unhedged. Net income and Adjusted EBITDAX are from continuing operations. Please see reconciliation of
Adjusted EBITDAX to net income at end of presentation. |
 ASSET
CHARACTERISTICS 8
Natural
Gas
18%
Oil
82%
Undeveloped
44%
Developed
56%
Oil
64%
Natural
Gas
36%
Selmo
45%
Thrace
20%
Other
20%
(1)
DeGolyer and MacNaughton reserves as of 12/31/2012, based on $108.30/barrel and
$8.94/Mcf. Goksu
9%
Molla 6%
Growth
Profile
(1)
1Q13 Production Profile
Reserve
Profile
(1) |
 TÜRKIYE: SOUTHEAST
9
Action Plan
•
Drill horizontal wells to
increase productivity
•
3D seismic of Molla
blocks
•
Expand 2012
discoveries (Goksu,
Bahar and Alibey)
•
Resume development at
Selmo with horizontal
wells
•
Prepare to drill on
licenses acquired in May
2013
TransAtlantic’s properties in southeastern Türkiye have common geology with
Syria and Iraq. GAZIANTEP
MOLLA –
ARPATEPE
SELMO
BAKUK -
IDIL |
 MOLLA
– ARPATEPE AREA
10
TransAtlantic’s
Arpatepe Field
TransAtlantic’s
Selmo Field
TransAtlantic’s
Bahar Field
TransAtlantic’s
Goksu Field
Shell/TPAO
Saribugday-1
Perenco’s
Kestal Field
(EUR 15 MMbo)
TransAtlantic’s
May 2013 Acquisition
TransAtlantic’s
Molla Field
TransAtlantic
3D Seismic Area
Bati Raman Field
Largest oil field in Türkiye |
 MOLLA
– ARPATEPE STACKED PAY POTENTIAL
11
Demonstrated
horizontal success with
Goksu 3H over
250 BOPD after ~5
months of production
Vertical discovery
(Bahar-1) IP after frac
at ~600 BOPD;
Horizontal currently
drilling
Tested 150 BOPD
(Bahar-1)
Potential resource
play
Oil
shows
–
untested
Selmo producing zone |
 MOLLA
– ARPATEPE AREA GRAVITY MAP
12
Field discoveries align well with gravity data; meaningful structural and stratigraphic
running room Kastel Field
(EUR 15 MMbo)
Bahar Field
(2P Reserves: 2.5 MMbo)
Goksu Field
(2P Reserves: 2.9 MMbo)
(1)
DeGolyer and MacNaughton reserves as of 12/31/2012, based on $108.30/barrel and
$8.94/Mcf. Arpatepe JV (TAT 50%)
Proved Structures
Gravity-Indicated Structures
TAT 100%
Molla 3D
Bati Raman Field
Largest oil field in Türkiye |
 SELMO
REMAPPING 13
Selmo Overview
•
Extensive work has been done to remap and model
Selmo to identify bypassed oil due to the extremely
fractured nature of the field
•
New dynamic model incorporates updated substructure
mapping with production and pressure histories to
determine the areas of the field that will most benefit
from a horizontal drilling campaign
•
We believe horizontal wellbores will allow pressure
drawdown that is more uniform across the length of the
wellbore and prevent water coning or premature
breakthrough of water
•
2013 budget provides for four horizontal wells in the
Middle Sinan Dolomite (MSD) and one horizontal well
in the Lower Sinan Dolomite (LSD) |
 SELMO
REMAPPING, CONTINUED 14
Selmo Horizontal Well Example
Middle Sinan Dolomite Structure |
 TÜRKIYE: NORTHWEST
15
Thrace Basin Natural Gas
Türkiye Corporation
(41.5% owned)
West
Northwest
Joint Area
with TPAO
(50%/50% )
Action Plan
•
Tekirdag development
project: low risk gas
production growth, 2 well
horizontal trial
•
Hayrabolu: evaluate
exploration and delineation
wells, overpressure below
1,500 meters
•
Final exploitation of Edirne
blocks (NW Thrace)
•
Limited development within
TPAO (Turkish Petroleum)
joint blocks
•
3D on Osmanli structure
near Thrace area “kitchen” |
 THRACE
BASIN: MEZARDERE FORMATION 16
Basin map illustrates source, kitchen, trap and pressure dynamics
TEKIRDAG
HAYRABOLU
YILDIRIM
GO
–
TEPE
OSMONLI |
 THRACE
BASIN: TEKIRDAG DEVELOPMENT 17
Development Program Characteristics:
•
Initial 88-well vertical development program covering approximately 5,000 acres of
the Tekirdag Field Area •
Plan 17 wells in Tekirdag area and 8 wells in Hayrabolu during 2013 (will likely adjust
downward to shift capital to recently acquired licenses in the southeast)
•
Two well horizontal test could reduce well count by 75%
•
Gross
well
costs
expected
to
range
between
$2.0
million
and
$3.0
million,
depending
upon
depth
and
completion
design
•
Gross
expected
ultimate
recovery
expected
to
exceed
70
Bcf
(1)
(1)
Internal estimate prepared 10/1/12
HAYRABOLU
TEKIRDAG
15 miles
25 kilometers |
 THRACE
BASIN: TEKIRDAG DEVELOPMENT 18
Each horizontal well could replace 4-5 vertical wells, significantly improving the
economics of the field |
 BULGARIA
19
Action Plan
Koynare (Deventci)
•
Currently finalizing 50% JV
•
Expect to drill Deventci-R2 in 2013
•
Conventional gas discovery in Jurassic-aged Orzirovo
•
If successful, plan to build pipeline to connect to central
grid at +/-$9/Mcf, shoot additional 3D seismic of the
multiple structures along Koynare fault trend
Stefanetz
•
November 2011 drilled a ~10,500 foot (3,200 meter)
Peshtene-R11 exploration well to core and test
Etropole formation
•
Awaiting revision to parliamentary legislation regarding
hydraulic fracture stimulation
Near the best oil and natural gas fields in the country
and existing natural gas infrastructure
ETROPOLE
SHALE
KOYNARE
CONCESSION
160,000 ACRES
DEVENRCI-R1
PESHTENE-R11
STEFENETZ
CONCESSION
(APPLICATION)
395,000 ACRES |
 INVESTMENT CONSIDERATIONS
Constructive Outlook
•
Horizontal and multi-stage completions have potential to
significantly increase production and improve economics from
known oil and natural gas deposits
•
More fields are present than originally believed (Goksu, Bahar
and Yildirim)
•
Expect improvements in drilling efficiency to improve well
economics and increase well count
•
JV would accelerate development
•
Incremental production will largely fall to bottom line without
significant increase in G&A or LOE
20
Strong Fundamentals
•
Very good pricing and netbacks
•
Terms remain favorable in Turkey and Bulgaria
•
Ramping up drilling activity to increase production
•
Newly acquired properties offer additional prospects |
 INVESTOR
CONTACT INFORMATION Taylor B. Miele
Director of Investor Relations
(214) 265-4746
taylor.miele@tapcor.com
Wil F. Saqueton
VP
-
Chief
Financial
Officer
(214) 265-4743
wil.saqueton@tapcor.com
Ian J. Delahunty
President
(214) 265-4780
ian.delahunty@tapcor.com
21 |
 Crude
Oil Supply/Demand WHY TURKEY?
22
Opportunity Set
Undersupplied:
•
Produces ~8% of crude oil consumed
•
Produces ~2% of natural gas consumed
Underexplored:
•
Known petroleum systems and attractive
geology
•
Opportunity for modern technology to make a
difference
Pro-Business:
•
Relatively laissez faire
•
12.5% royalty, 20% corporate tax
Source: US Energy Information Administration (EIA)
Source:
US
Energy
Information
Administration
(EIA).
Most
recent
data
available
is
2011.
Source: World Bank. Most recent data available is 2011.
Natural Gas Supply/Demand
Gross Domestic Product |
 MOLLA:
MARDIN POTENTIAL; GOKSU DISCOVERY 23
Molla: Mardin Formation Overview
•
Fractured Cretaceous carbonate present across the region
•
Initial vertical discoveries bolstered by recent application of horizontal drilling
processes •
Total
1P
reserves
of
0.6
MMbbls
(1)
;
Total
2P
reserves
of
2.9
MMbbls
(1)
•
Cumulative production over 60,000 bbls
•
Initial flow rates were 400-500 BOPD in February 2012
•
Flowing ~250 BOPD after 5 months of production
•
Cumulative production over 70,000 bbls
•
TransAtlantic’s first horizontal completion, 1,600 foot lateral
•
Drilled and completed for approximately $3.5 million
•
Initial production 250 BOPD
•
Drilled and completed for approximately $2.5 million
•
Westerly field extension
(1)
DeGolyer and MacNaughton reserves as of 12/31/2012, based on $108.30/barrel and
$8.94/Mcf. Goksu-2
Goksu-3H
Goksu-4H |
 MOLLA:
BEDINAN AND HAZRO DISCOVERY (1)
DeGolyer and MacNaughton reserves as of 12/31/2012, based on $108.30/barrel and
$8.94/Mcf. 24 |
 MOLLA:
BAHAR-1 MARDIN TARGETS 25 |
 MOLLA:
BAHAR-1 HAZRO TARGETS 26 |
 MOLLA:
BAHAR-1 BEDINAN TARGET 27 |
 THRACE
BASIN: TEKIRDAG DEVELOPMENT 28
Development Program Characteristics:
•
Initial 88-well vertical development program covering approximately 5,000 acres of
the Tekirdag Field Area •
Plan 17 wells in Tekirdag area and 8 wells in Hayrabolu during 2013 (will likely adjust
downward to shift capital to recently acquired licenses in the southeast)
•
Two well horizontal test could reduce well count by 75%
•
Gross
well
costs
expected
to
range
between
$2.0
million
and
$3.0
million,
depending
upon
total
depth
and
completion
design
•
Gross
expected
ultimate
recovery
expected
to
exceed
70
Bcf
(1)
(1)
Internal estimate prepared 10/1/12.
HAYRABOLU
TEKIRDAG
15 miles
25 kilometers |
 THRACE
BASIN: HAYRABOLU TREND 29
11,000 prospective acres |
 BULGARIA
SEISMIC AND WELL DATABASE 30
Deventci 3D
Seismic Survey
75 km^2 |
 BULGARIA:
DEVENTCI-R1 DISCOVERY WELL 31 |
 HEDGE
PROFILE 32
Data as of 3/31/2013. |
 EBITDAX
RECONCILIATION 33
For the three
months ended
$US millions
March 31, 2013
Net income from continuing operations
$3.0
Less:
Interest and other, net
0.5
Income tax expense
2.3
Exploration, abandonment, and impairment
3.9
Seismic
0.1
Foreign exchange loss
0.5
Share-based compensation
0.4
Unrealized derivative gain
(0.5)
Accretion of asset retirement obligation
0.1
Depreciation, depletion and amortization
9.0
Net other items
0.2
Adjusted EBITDAX from continuing operations
$19.5
This presentation references estimated EBITDAX, which is a non-GAAP financial
measure that represents earnings from continuing operations before income
taxes, interest, depreciation, depletion, amortization, impairment, abandonment
and exploration expense. The Company
believes EBITDAX assists management and investors in comparing the
Company’s performance and ability to fund capital expenditures and working
capital requirements on a consistent basis without regard to depreciation,
depletion and amortization, impairment of natural gas and oil properties and
exploration expenses, which can vary significantly from period to period.
In addition, management uses EBITDAX as a financial measure to evaluate the
Company’s operating performance. EBITDAX is also widely used by
investors and rating agencies.
EBITDAX is not a measure of financial performance under GAAP. Accordingly,
it should not be considered as a substitute for net income, income from
operations, or cash flow provided by operating activities prepared in
accordance with GAAP. Net income, income from operations, or cash flow provided
by operating activities may vary materially from EBITDAX. Investors should
carefully consider the specific items included in the computation of
EBITDAX. The Company has disclosed EBITDAX to permit a comparative
analysis of its operating performance and debt servicing ability relative to
other companies. |
 PV-10
RECONCILIATION 34
$US thousands
Total PV-10:
$511,075
Future income taxes:
(106,411)
Discount of future income
taxes at 10% per annum:
31,213
Standardized measure:
$435,880
The PV-10 value of the estimated future net revenue are not intended to represent
the current market value of the estimated oil and natural gas reserves we own.
Management believes that the presentation of PV-10, while not a financial measure in accordance with U.S. GAAP, provides
useful information to investors because it is widely used by professional analysts and
sophisticated investors in evaluating oil and natural gas companies. Because
many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid,
the use of a pre-tax measure is valuable when comparing companies based on
reserves. PV-10 is not a measure of financial or operating performance under
U.S. GAAP. PV-10 should not be considered as an alternative to the
standardized measure as defined under U.S. GAAP. The following table
provides a reconciliation of our PV-10 to our standardized measure: |