Triton Announces 2008 Year-End Reserves
06 March 2009 - 10:43AM
Marketwired Canada
Triton Energy Corp. (TSX VENTURE:TEX) ("Triton" or the "Corporation") is pleased
to provide the following summary information from its annual independent reserve
evaluation completed by AJM Petroleum Consultants for all of the Corporation's
properties effective December 31, 2008 (the "AJM Report"). These estimates were
prepared in accordance with National Instrument 51-101 Standards of Disclosure
for Oil and Gas Activities (NI 51-101). Triton anticipates releasing its audited
year-end financial statements on or about April 22, 2009.
2008 HIGHLIGHTS
- Average daily production increased approximately 30% to 814 barrels of oil
equivalent compared to 629 barrels of oil equivalent in 2007;
- Triton exited 2008 with average daily production of approximately 1,100
barrels of oil equivalent;
- Total Proved Reserves increased by 35% to 1,626.5 thousand barrels of oil
equivalent;
- Total Proved plus Probable Reserves increased by 43% to 2,387.4 thousand
barrels of oil equivalent;
- Triton replaced estimated production by 340% with Proved plus Probable
Reserves additions;
- The Corporation increased its Reserves Life Index on a Proved plus Probable
Reserves basis to 5.9 years, calculated by dividing reserves by the 2008
year-end exit production rate;
- Estimated finding and development costs, including changes in future
development costs, improved to $20.38 per barrel of oil equivalent on a Proved
Reserves basis and $14.65 per barrel of oil equivalent on a Proved plus Probable
Reserves basis;
- Excluding changes in future development costs, estimated finding and
development costs were $17.48 per barrel of oil equivalent on a Proved Reserves
basis and $11.85 per barrel of oil equivalent on a Proved plus Probable Reserves
basis;
- The net present value (before tax discounted at ten percent) of future net
revenue from total Proved plus Probable Reserves increased by 56% to $43.6
million.
RESERVES
The following table summarizes the Corporation's gross and net interests in
proved and probable reserves at December 31, 2008 as assessed in the AJM Report
using their December 31, 2008 forecast prices and cost assumptions.
---------------------------------------------------------
RESERVES (1)(2)(3)
---------------------------------------------------------
LIGHT AND
MEDIUM OIL HEAVY OIL NATURAL GAS(4)
---------------- ---------------- ---------------------
RESERVES Gross Net Gross Net Gross Net
CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mmcf)
---------------- ------- ------- -------- ------ ----------- --------
Proved Developed
Producing 86.1 67.0 - - 5,155.9 3,678.7
Non-Producing 92.5 73.1 - - 2,497.5 1,860.1
Proved
Undeveloped - - - - 871.8 543.0
------- ------- -------- ------ ----------- --------
TOTAL PROVED 178.6 140.1 - - 8,525.2 6,081.7
PROBABLE 89.5 68.1 - - 3,961.9 2,793.2
------- ------- -------- ------ ----------- --------
TOTAL PROVED
PLUS PROBABLE 268.1 208.2 - - 12,487.1 8,874.9
------- ------- -------- ------ ----------- --------
------- ------- -------- ------ ----------- --------
---------------------------------------------------------
RESERVES (1)(2)(3)
---------------------------------------------------------
NATURAL GAS BARRELS OF OIL
LIQUIDS EQUIVALENT(5)
------------------ --------------------
RESERVES Gross Net Gross Net
CATEGORY (Mbbl) (Mbbl) (Mboe) (Mboe)
------------------- ------------------ --------------------
Proved Developed
Producing 13.4 8.1 958.8 688.2
Non-Producing 2.5 1.6 511.3 384.7
Proved
Undeveloped 11.1 6.4 156.4 96.8
------------------ --------------------
TOTAL PROVED 27.0 16.0 1,626.5 1,169.8
PROBABLE 11.2 6.7 760.9 540.4
------------------ --------------------
TOTAL PROVED
PLUS PROBABLE 38.2 22.8 2,387.4 1,710.1
------------------ --------------------
------------------ --------------------
(1) Numbers in this table are subject to round off error.
(2) Gross reserves are the Corporation's working interest share prior to the
deduction of royalty obligations and inclusion of royalty interests.
(3) Net reserves are the Corporation's working interest share after the
deduction of royalty obligations and the inclusion of royalty interests.
(4) Natural gas volumes include solution gas volumes associated with the
Corporation's light and medium crude oil reserves.
(5) Natural gas is converted to barrels of oil equivalent ("boe") at a
ratio of six thousand standard cubic feet to one barrel of oil.
NET PRESENT VALUES OF FUTURE NET REVENUE
The following table summarizes Triton's share of the net present value of future
net revenue attributable to its reserves before tax but prior to the provision
for interest and general and administrative expenses.
NET PRESENT VALUES OF FUTURE NET REVENUE(1)(2)(3)(4)(5)(6)
----------------------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
----------------------------------------------------------
RESERVES 0 5 10 15 20
CATEGORY (M$) (M$) (M$) (M$) (M$)
----------------- ---------- --------- ---------- ---------- ----------
Proved Developed
Producing 27,315.4 22,925.3 19,887.1 17,661.3 15,959.1
Non-Producing 16,140.4 11,753.6 8,921.4 6,992.8 5,622.4
Proved Undeveloped 3,449.3 2,715.4 2,176.8 1,771.4 1,459.6
---------- --------- ---------- ---------- ----------
TOTAL PROVED 46,905.0 37,394.3 30,985.3 26,425.5 23,041.0
PROBABLE 26,368.0 17,367.0 12,577.8 9,647.7 7,698.7
---------- --------- ---------- ---------- ----------
TOTAL PROVED PLUS
PROBABLE 73,273.0 54,761.2 43,563.0 36,073.3 30,739.7
---------- --------- ---------- ---------- ----------
---------- --------- ---------- ---------- ----------
(1) Utilizes AJM Petroleum Consultants price forecasts as of December 31,
2008 as detailed below.
(2) Values are net of abandonment liabilities.
(3) Numbers in this table are subject to round off error.
(4) The net present values of future net revenue may not represent fair
market value.
(5) The net present values of future net revenue do not take into account
the Alberta government's transitional royalties.
(6) The net present values of future net revenue do not take into account
the short-term incentives announced by the Alberta government on
March 3, 2009.
PRICE FORECASTS
The following price forecasts were used to determine future revenues from
the Corporation's reserves.
OIL
-----------------------------------------
WTI Edmonton Bow River
Cushing Oil Price Hardisty
Oklahoma 40 API 25 API
Year ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl)
----------- ------------ ------------ ------------
Forecast
2009 $ 55.00 $ 65.40 $ 50.40
2010 $ 76.50 $ 87.20 $ 65.20
2011 $ 88.45 $ 96.50 $ 70.50
2012 $ 100.80 $ 104.30 $ 76.30
2013 $ 108.25 $ 112.05 $ 84.05
2014 $ 110.40 $ 114.25 $ 86.25
2015 $ 112.60 $ 116.55 $ 88.55
2016 $ 114.84 $ 118.90 $ 90.90
2017 $ 117.15 $ 121.25 $ 93.25
2018 $ 119.50 $ 123.70 $ 95.70
2019 $ 121.90 $ 126.15 $ 98.15
Alberta AECO Pentanes Butanes
Average Gas Plus Price Inflation Exchange
Price Edmonton Edmonton Rates(1) Rate(2)
Year ($Cdn/Mcf) ($Cdn/Bbl) ($Cdn/Bbl) %/Year ($US/$Cdn)
--------------- ------------ ------------ ---------- -----------
Forecast
2009 $ 7.00 $ 68.65 $ 52.30 0.0% 0.820
2010 $ 8.05 $ 91.55 $ 69.75 2.0% 0.860
2011 $ 8.20 $ 101.35 $ 77.20 2.0% 0.900
2012 $ 9.00 $ 109.50 $ 83.45 2.0% 0.950
2013 $ 9.75 $ 117.65 $ 89.65 2.0% 0.950
2014 $ 9.95 $ 119.95 $ 91.40 2.0% 0.950
2015 $ 10.15 $ 122.35 $ 93.25 2.0% 0.950
2016 $ 10.35 $ 124.85 $ 95.10 2.0% 0.950
2017 $ 10.55 $ 127.30 $ 97.00 2.0% 0.950
2018 $ 10.75 $ 129.90 $ 98.95 2.0% 0.950
2019 $ 10.95 $ 132.45 $ 100.90 2.0% 0.950
Escalated oil, gas and product prices at
2020+ approximately 2% per year thereafter 2.0% 0.950
(1) Inflation rates for forecasting prices and costs.
(2) Exchange rates used to generate the benchmark reference prices in this
table.
FINDING AND DEVELOPMENT COSTS
The Corporation's finding and development costs including changes in future
development costs ("FDC") for 2008 are estimated to be $20.38 per barrel of oil
equivalent on a Proved Reserves basis and $14.65 on a Proved plus Probable
("P+P") Reserves basis.
FINDING AND DEVELOPMENT ("F&D") COSTS 2008(1) 2007 2006
----------------------------------------- ----------- -------- --------
Capital Expenditures (millions)(2) $ 15.2 $ 17.5 $ 11.4
Proved Reserves Added (mboe) 872 983 494
P+P Reserves Added (mboe) 1,286 1,318 631
F&D Costs (including FDC)/boe (Proved)(3) $ 20.38 $ 20.86 $ 24.79
F&D Costs (including FDC)/boe (P+P)(3) $ 14.65 $ 15.62 $ 19.41
F&D Costs (excluding FDC)/boe (Proved)(4) $ 17.48 $ 17.77 $ 23.02
F&D Costs (excluding FDC)/boe (P+P)(4) $ 11.85 $ 13.25 $ 18.02
(1) Certain information used in the foregoing calculations includes
information based on estimated unaudited financial results that may
change on completion of the audited financial statements for the year
ended December 31 2008.
(2) Being exploration and development costs. The aggregate of the
exploration and development costs incurred in the most recent financial
year and the change during that year in estimated future development
costs generally will not reflect total finding and development costs
related to reserve additions for that year.
(3) The three-year average F&D costs (including FDC)/boe is $22.01 (Proved
Reserves) and $16.56 (P+P Reserves).
(4) The three-year average F&D costs (excluding FDC)/boe is $19.42 (Proved
Reserves) and $14.37 (P+P Reserves).
RESERVES COMMITTEE
Triton has a Reserves Committee comprised of a majority of independent board
members, which reviews the qualifications and appointment of the independent
reserve evaluators. The Reserves Committee also reviews the process for
providing information to the evaluators and meets with the independent
evaluators to discuss the procedures used in the independent report, to review
major property assessments and to discuss any areas of risk. The AJM Report was
reviewed by Triton's Reserves Committee and subsequently accepted by the
Corporation's Board of Directors on March 5, 2009.
OUTLOOK
In the near term, petroleum and natural gas prices are expected to remain at or
near their current multi-year lows, reflecting the broadening impact of the deep
world economic recession. Petroleum and natural gas producers in Alberta are
also feeling the effects of the new royalty regime that came into effect January
1, 2009. As a result, cash flows in 2009 are expected to be significantly lower
than last year.
Earlier this week, the Alberta government provided some much needed aid to the
petroleum and natural gas industry in Alberta when it announced some new
incentives to help industry participants during these very difficult economic
times. Two of these new incentives are intended to assist petroleum and natural
gas explorers, namely a new well incentive program and a drilling royalty credit
for new wells. Wells brought on production after April 1, 2009 will pay a five
percent royalty for the first twelve months, subject to certain limits, and a
drilling credit of $200 per meter drilled can be earned and applied to Alberta
Crown royalties, also subject to certain limits. More details of these new
incentives can be found on the Alberta government website.
Triton is currently reviewing its capital expenditure plans for the remainder of
2009 in light of these new incentives. There are two obvious potential benefits
for Triton resulting from these new incentives. Firstly, the five percent
royalty rate for wells placed on production after April 1, 2009 will improve
economics for several wells that Triton has completed but not yet placed on
production. Secondly, exploiting the $200 per meter drilling credit would have a
positive impact on the Corporation's cash flow in the second half of 2009 by
reducing future royalties. The magnitude of the impact has not yet been
determined.
Triton is a Calgary, Alberta based corporation engaged in the exploration,
development and production of petroleum and natural gas. The Corporation's
common shares are listed on the TSX Venture Exchange under the trading symbol
"TEZ".
Advisories
This news release may include forward-looking statements including opinions,
assumptions, estimates and management's assessment of future plans and
operations, production, proved and proved plus probable reserves, commodity
prices, estimated finding and development costs and the effects on cash flows
attributable to the new royalty incentives. When used in this document, the
words "anticipate," "believe," "estimate," "expect," "intent," "may," "project,"
"plan", "should" and similar expressions are intended to be among the statements
that identify forward-looking statements. Forward-looking statements are subject
to a wide range of risks and uncertainties, and although the Corporation
believes that the expectations represented by such forward-looking statements
are reasonable, there can be no assurance that such expectations will be
realized. Any number of important factors could cause actual results to differ
materially from those in the forward-looking statements including, but not
limited to, risks associated with oil and gas exploration, development,
exploitation, results from testing, production, marketing and transportation,
the volatility of oil and gas prices, currency fluctuations, the ability to
implement corporate strategies, the state of domestic capital markets, the
ability to obtain financing, incorrect assessment of the value of acquisitions,
failure to realize the anticipated benefits of acquisitions, changes in oil and
gas acquisition and drilling programs, delays resulting from inability to obtain
required regulatory approvals, delays resulting from inability to obtain
drilling rigs and other services, delays in tie-in operations, results from
testing, environmental risks, competition from other producers, imprecision of
reserve estimates, changes in general economic conditions and other factors more
fully described from time to time in the reports and filings made by Triton with
securities regulatory authorities. Readers are cautioned not to place undue
reliance on forward-looking statements, as no assurances can be given as to
future results, levels of activity or achievements. Except as required by
applicable securities laws, the Corporation does not undertake any obligation to
publicly update or revise any forward-looking statements.
Certain financial information included in this news release for the year ended
December 31, 2008, including exploration and development expenditures used in
the calculation of finding and development costs are based on estimated
unaudited financial results for the period then ended and may change upon
completion of the audited financial statements for the year ended December 31,
2008 and the changes could be material.
Disclosure provided herein in respect of barrels of oil equivalent ("boe") may
be misleading, particularly if used in isolation. A boe conversion ratio of six
thousand standard cubic feet of natural gas to one barrel of oil is based on an
energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead.
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