Paramount Energy Trust Releases 2007 Year-End Reserves, Confirms February 2008 Distribution, Updates Hedging, and Announces Appointment of New Director
(TSX: PMT.UN) Paramount Energy Trust (“PET” or the “Trust”) confirmed today that its distribution to be paid on March 17, 2008 in respect of income received by PET for the month of February 2008, for Unitholders of record on February 29, 2008, will be $0.10 per Trust Unit. The ex-distribution date is February 27, 2008. The February 2008 distribution brings cumulative distributions paid since the inception of the Trust in February 2003 to $12.124 per Trust Unit.
Natural gas prices continue to be highly volatile, largely around uncertainty regarding weather and its effect on natural gas demand and storage and the global factors influencing LNG shipments to North America. PET continues to be cautious in its outlook with respect to near term natural gas prices and is actively managing its forward gas price exposure to mitigate risk. Financial and physical forward sales arrangements at the AECO and NYMEX trading hubs as at February 7, 2008 are as follows:
———————————————————————– —– —————————————————————– ———– Volumes % of Current at Budget Forward Type of AECO (2) Production Price Price contract (GJ/d) (3) ($/GJ) ($/GJ) Term —————————————————————————- —————————————————————————- Financial 75,000 7.262 March 2008 Physical 12,500 7.450 March 2008 —————————————————————————- Period total, March 2008 net (1) 87,500 41% 7.289 7.10 —————————————————————————- —————————————————————————- Financial 59,500 7.285 April – October 2008 Physical 5,000 6.683 April – October 2008 —————————————————————————- Period total AECO, net (1) 64,500 7.238 7.13 April – October 2008 —————————————————————————- —————————————————————————- Financial NYMEX 10,000 7.700 US$ April – October 2008 —————————————————————————- Period total NYMEX, net (1) 10,000 7.700 US$ 8.39US$ April – October 2008 —————————————————————————- Period total, net (1) 74,500 35% April – October 2008 —————————————————————————- —————————————————————————- November 2008 – Financial 93,500 7.732 March 2009 —————————————————————————- Period total, November 2008 – net (1) 93,500 44% 7.732 7.97 March 2009 —————————————————————————- —————————————————————————- Financial 27,500 7.122 April – October 2009 —————————————————————————- Period total, net (1) 27,500 13% 7.122 7.16 April – October 2009 —————————————————————————- —————————————————————————- (1) Weighted average prices are calculated by netting the volumes of the financial and physical sold/bought contracts together and measuring the net volume at the weighted average “sold” price for the financial and physical contracts. (2) All transactions at AECO unless identified specifically as a NYMEX transaction. (3) Includes projected actual and gas over bitumen deemed production volumes.
In addition, PET realized gains totalling approximately $2 million in January 2008 on crystallization of forward summer 2008 and winter 2008-2009 positions. Based on current natural gas prices, PET expects to maintain monthly distributions at the current level for the foreseeable future. Incorporating PET’s current hedging portfolio and the forward market for natural gas prices into the Trust’s production, operations and cash flow forecasts for 2008, the current level of distribution annualized would result in an average payout ratio of approximately 53 percent for 2008 and bank debt at year end of approximately $300 million. The Trust continues to focus on what we believe is a sustainable distribution model that balances short term cash returns to our Unitholders and long term value creation. PET reviews distributions on a monthly basis. Future distributions are subject to change as dictated by changes in commodity price markets, operations and future business development opportunities.
PET is also very pleased to announce the appointment of Robert A. Maitland to the Trust’s Board of Directors, effective February 7, 2008. Mr. Maitland is a Chartered Accountant with 32 years of senior business experience, primarily in the oil and gas industry. He has in-depth knowledge of audit and corporate governance, and has recently completed the Institute of Corporate Directors – Director Education Program. We are confident that Mr. Maitland’s past experience in management and administration, accounting, corporate finance, as well as his past legal, income tax and corporate secretarial responsibilities will be an asset to PET’s Management, Board of Directors and Unitholders.
Following is a summary of PET’s year-end 2007 reserves information, as evaluated by the independent engineering firm McDaniel and Associates Consultants Ltd. (“McDaniel”).
YEAR END RESERVE EVALUATION HIGHLIGHTS
– In 2007, the Trust added 180.0 Bcfe of proved reserves and 130.7 Bcfe of probable reserves for total reserve additions of 310.7 Bcfe of proved and probable reserves, excluding production.
– Offset by production of 62.3 Bcfe in 2007, proved reserves increased 66 percent from 177.1 Bcfe at year-end 2006 to 294.8 Bcfe at year-end 2007, and proved and probable reserves increased 95 percent to 509.9 Bcfe, primarily due to the significant reserve additions resulting from the acquisition of natural gas properties in east central Alberta (“Birchwavy Acquisition”) completed in June 2007 and the success of the Trust’s capital spending programs in 2007.
– Proved and probable reserves per Trust Unit increased 53 percent at year-end 2007 to 4.65 Mcfe per Trust Unit from 3.04 Mcfe per Trust Unit as at December 31, 2006.
– Excluding future development costs, PET realized finding, development and acquisition costs of $2.81 per Mcfe ($16.86 per BOE) on a proved reserves basis and $1.63 per Mcfe ($9.78 per BOE) on a proved and probable reserves basis in 2007.
– Including future development costs, PET realized finding, development and acquisition costs of $3.26 per Mcfe ($19.56 per BOE) on a proved reserves basis and $2.56 per Mcfe ($15.36 per BOE) on a proved and probable reserves basis in 2007.
– The Trust’s reserve to production ratio (“reserve life index”) increased to 7.6 years on a proved and probable reserves basis (4.7 years on a proved reserves basis) at year-end 2007, as compared to 4.9 years (3.6 years on a proved basis) in 2006.
RESERVES DISCLOSURE
Company interest reserves included herein are before royalty burdens and including royalty interests. Reserves information is based on an independent reserves evaluation report prepared by McDaniel January 31, 2008 with an effective date of December 31, 2007, and has been prepared in accordance with National Instrument 51-101 (“NI 51-101″) using McDaniel’s forecast prices and costs. Complete NI 51-101 reserves disclosure including after-tax reserve values, reserves by major property and abandonment costs will be included in PET’s Annual Information Form (“AIF”), which will be filed in March 2008. PET reports the results of the Trust’s 93 percent-owned subsidiary Severo Energy Corp. (“Severo”) using consolidated accounting practices, and therefore the amounts shown include 100 percent of the volumes and values related to the natural gas reserves of Severo.
Approximately 98 percent of PET’s proved and proved and probable reserves are natural gas and as such the Trust reports reserves in Mcf equivalent (Mcfe). Mcfe may be misleading, particularly if used in isolation. In accordance with NI 51-101 a Mcfe conversion ratio for oil of 1 Bbl: 6 Mcf has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead.
RESERVES SUMMARY AT YEAR-END 2007
Company Interest (Working Interest + Royalty Interest) —————————————————————————- —————————————————————————- Light and Natural Gas Natural Gas Medium Crude Natural Gas Liquids Equivalent Oil (MBbl) (MMcfe) (MBbl) (MMcfe) —————————————————————————- Proved Producing 1,013 225,161 16 231,339 Proved Non-Producing 20 16,475 1 16,598 Proved Undeveloped 137 46,021 – 46,843 —————————————————————————- Total Proved 1,170 287,656 17 294,780 —————————————————————————- Total Probable 449 212,401 5 215,126 —————————————————————————- Total Proved and Probable 1,619 500,057 22 509,907 —————————————————————————- —————————————————————————- Gross Interest (Working Interest) —————————————————————————- —————————————————————————- Light and Natural Gas Natural Gas Medium Crude Natural Gas Liquids Equivalent Oil (MBbl) (MMcfe) (MBbl) (MMcfe) —————————————————————————- Proved Producing 961 222,344 16 228,206 Proved Non-Producing 20 16,321 1 16,444 Proved Undeveloped 137 45,770 – 46,592 —————————————————————————- Total Proved 1,118 284,435 17 291,243 —————————————————————————- Total Probable 441 211,238 5 213,916 —————————————————————————- Proved and Probable 1,559 495,673 22 505,159 —————————————————————————- —————————————————————————- Net Interest (Company Interest – Royalties Payable) —————————————————————————- —————————————————————————- Light and Natural Gas Natural Gas Medium Crude Natural Gas Liquids Equivalent Oil (MBbl) (MMcfe) (MBbl) (MMcfe) —————————————————————————- Proved Producing 931 183,810 12 189,467 Proved Non-Producing 18 13,839 0 13,949 Proved Undeveloped 104 38,595 – 39,217 —————————————————————————- Total Proved 1,053 236,244 12 242,633 —————————————————————————- Total Probable 404 174,860 4 177,306 —————————————————————————- Proved and Probable 1,457 411,104 16 419,939 —————————————————————————- —————————————————————————- RESERVES RECONCILIATION Company Interest (Working Interest + Royalty Interest) —————————————————————————- —————————————————————————- Natural Gas Equivalent (MMcfe) —————————————————————————- TOTAL PROVED Opening Balance 177,139 Discoveries and Extensions 24,096 Technical Revisions 11,585 Acquisitions, net of Dispositions 145,018 Production (62,318) Economic Factors (740) Closing Balance 294,780 —————————————————————————- Natural Gas Equivalent (MMcfe) —————————————————————————- PROBABLE Opening Balance 84,360 Discoveries and Extensions 9,822 Technical Revisions (10,187) Acquisitions, net of Dispositions 131,063 Production – Economic Factors 69 Closing Balance 215,127 —————————————————————————- Natural Gas Equivalent (MMcfe) —————————————————————————- PROVED AND PROBABLE Opening Balance 261,499 Discoveries and Extensions 33,918 Technical Revisions 1,398 Acquisitions, net of Dispositions 276,081 Production (62,318) Economic Factors (671) Closing Balance 509,907 —————————————————————————- —————————————————————————-
RESERVE LIFE INDEX
PET’s proved and probable reserves to production ratio, also referred to as reserve life index (“RLI”) was 7.6 years at year-end 2007 while the proved RLI was 4.7 years, based upon the 2008 production estimates in the McDaniel Report. The following table summarizes PET’s historical calculated RLI.
Reserve Life Index (1) —————————————————————————- —————————————————————————- 2007 2006 2005 2004 2003 —————————————————————————- Total Proved 4.7 3.6 4.0 4.5 5.2 Proved and Probable 7.6 4.9 5.4 5.6 6.2 —————————————————————————- —————————————————————————- (1) Calculated as year end reserves divided by year one production estimate from McDaniel Report.
NET PRESENT VALUE SUMMARY
PET’s light and medium oil, natural gas and natural gas liquids reserves were evaluated by McDaniel using McDaniel’s product price forecasts effective January 1, 2008 prior to provision for income taxes, interest, debt service charges and general and administrative expenses. The following table summarizes the net present value (“NPV”) of cash flow at January 1, 2008, assuming various discount rates. It should not be assumed that the discounted future net cash flows estimated by McDaniel represent the fair market value of the potential future production revenue of the Trust.
NPV of Cash Flow Using McDaniel January 1, 2008 Forecast Prices and Costs —————————————————————————- —————————————————————————- NI 51-101 Net Discounted Discounted Discounted Discounted Interest Undiscounted at 5% at 10% at 15% at 20% —————————————————————————- ($MM) Proved Producing 1,056,412 883,487 772,606 692,366 630,582 Proved Non-Producing (429) 9,395 11,426 11,147 10,223 Proved Undeveloped 114,044 79,116 55,088 38,282 26,338 —————————————————————————- Total Proved 1,170,026 971,998 839,120 741,795 667,142 —————————————————————————- Total Probable 767,480 508,989 361,855 270,622 210,875 —————————————————————————- Total Proved and Probable 1,937,507 1,480,986 1,200,975 1,012,416 878,018 —————————————————————————- —————————————————————————-
At a 10 percent discount factor, the proved producing reserves comprise 64 percent of the proved and probable value while total proved reserves account for 70 percent of the proved and probable value. McDaniel’s price forecast utilized in the evaluation is summarized below.
McDaniel January 1, 2008 Price Forecast —————————————————————————- —————————————————————————- West Texas Intermediate Edmonton Light Natural Gas Foreign Year Crude Oil Crude Oil at AECO Exchange ($US/Bbl) ($Cdn/Bbl) ($Cdn/GJ) ($US/$Cdn) —————————————————————————- 2008 90.00 89.00 6.45 1.00 2009 86.70 85.70 7.00 1.00 2010 83.20 82.20 7.00 1.00 2011 79.60 78.50 7.00 1.00 2012 78.50 77.40 7.10 1.00 2013 77.30 76.20 7.30 1.00 2014 78.80 77.70 7.55 1.00 2015 80.40 79.30 7.80 1.00 2016 82.00 80.80 8.00 1.00 2017 83.70 82.50 8.25 1.00 2018 85.30 84.10 8.45 1.00 2019 87.00 85.80 8.70 1.00 2020 88.80 87.50 8.95 1.00 2021 90.60 89.30 9.20 1.00 2022 92.40 91.10 9.40 1.00 Escalate thereafter at +2.00% +2.00% +2.00% 1.00 —————————————————————————- —————————————————————————-
EFFECT OF NEW ALBERTA ROYALTY REGIME
On October 25, 2007, the Government of Alberta announced a “New Royalty Framework” for oil and natural gas royalties in the Province of Alberta. New royalty rates will apply to all production effective January 1, 2009. While detailed Regulations have yet to be released, PET’s initial assessment is that, based on the Trust’s current profile of well productivity and at various natural gas prices, the effect of the new royalty framework on cash flow would be approximately as shown below. Royalty rates would rise relative to their current levels at higher gas prices, and decrease relative to their current levels at lower gas prices.
Estimated Change in Royalty Rate (1) —————————————————————————- —————————————————————————- AECO Gas Price ($/GJ) $5.00 $6.00 $7.00 $8.00 $10.00 —————————————————————————- Estimated Crown Royalty Rate in 2009 under Current Royalties 17.4% 17.4% 17.4% 17.4% 17.4% Estimated Crown Royalty Rate in 2009 under Revised Royalties 6.8% 11.3% 15.8% 18.8% 24.9% Increase (Decrease) in Royalty Rate (percentage points) (10.6%) (6.1%) (1.6%) 1.4% 7.5% Percentage Increase (Decrease) in Royalty Rate (%) (60.6%) (34.9%) (9.4%) 8.0% 42.3% —————————————————————————- —————————————————————————- (1) PET estimated average 2009 well productivity based on McDaniel Report is 175 Mcf/d.
With respect to the future cash flow related to the reserves booked in the McDaniel Report, the declining productivity profile assumed from the “blow-down” assumption of the McDaniel Report would result in lower royalty rates in future years and increases in the future net revenue from PET’s proved and probable reserves at various gas prices, discounted at 5 percent as shown below:
Estimated Change in NPV of Future Net Revenue Resulting From Proposed Change in Alberta Royalty Framework —————————————————————————- —————————————————————————- AECO Gas Price ($/GJ) Discounted at 5% $6.00(2) McDaniel(1) $8.00(2) $10.00(2) —————————————————————————- ($MM) Increase (Decrease) in Net Present Value Due to Price Change from McDaniel Prices(3) $(441.2) – $197.5 $825.5 Increase (Decrease) in Net Present Value Due to New Royalty Regime(4) $83.7 $58.0 $48.5 $(37.2) —————————————————————————- —————————————————————————- (1) McDaniel price forecast at January 1, 2008. See “NET PRESENT VALUE SUMMARY – NPV of Cash Flow Using McDaniel January 1, 2008 Forecast Prices and Costs” (2) AECO Spot price held constant with zero inflation. (3) Increase (Decrease) in net present value of future revenue assuming current royalty framework and forecast gas price indicated as compared to the McDaniel forecast. (4) Increase (Decrease) in net present value of future revenue related to the proposed royalty framework assuming the forecast gas price indicated.
NET ASSET VALUE
The following net asset value (“NAV”) table shows what is normally referred to as a “produce-out” NAV calculation under which the current value of the Trust’s reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of PET Units. PET runs its business on a going-concern basis, investing in opportunities to add value, improve profitability and increase reserves which enhance the Trust’s NAV beyond the amounts shown in its annual reserve evaluation.
Net Asset Value at December 31, 2007 —————————————————————————- —————————————————————————- Net Asset Value at Discounted Discounted Discounted December 31, 2007(1) Undiscounted at 5% at 8% at 10% —————————————————————————- ($MM except as noted) Total Proved plus Probable Reserves (2) 1,937.5 1,481.0 1,298.9 1,201.0 Increment for Current Gas Prices (3) 48.3 44.7 43.0 41.6 Undeveloped Land (4) 140.1 140.1 140.1 140.1 Effect of New Alberta Royalty Regime(5) 77.1 58.0 50.0 44.9 Net Bank Debt (unaudited) (337.5) (337.5) (337.5) (337.5) Convertible Debentures (unaudited) (236.1) (236.1) (236.1) (236.1) —————————————————————————- Net Asset Value 1,629.4 1,150.2 958.4 854.0 —————————————————————————- Trust Units Outstanding (MM) – basic 109.6 109.6 109.6 109.6 —————————————————————————- Net Asset Value per Trust Unit ($/Unit) $14.87 $10.50 $8.75 $7.79 —————————————————————————- —————————————————————————- (1) Financial information is per PET’s 2007 unaudited consolidated financial statements. (2) Reserve values per McDaniel Report as at December 31, 2007. (3) The average AECO gas price assumed in the McDaniel Report averaged $6.72/GJ for 2008 and 2009. At February 4, 2008 the forward market for AECO natural gas averaged $7.19 per GJ for 2008, 2009 and 2010. An increment for the higher forward prices has been included in this net asset value calculation. (4) Internal estimate. (5) See “Effect of New Alberta Royalty Regime” above.
In the absence of adding reserves to the Trust, the NAV per Trust Unit will decline as the reserves are produced out. The cash flow generated by the production relates directly to the cash distributions paid to Unitholders. The above evaluation includes future capital expenditure expectations required to bring undeveloped reserves recognized by McDaniel that meet the criteria for booking under NI 51-101 on production. The above evaluation does not consider those opportunities in the Trust’s extensive prospect inventory that are not captured in the NI 51-101 evaluation.
In order to determine the “going concern” value of the Trust, a more detailed independent assessment would be required of the upside potential of specific properties and the ability of the PET team to continue to make value-adding capital expenditures. At inception of the Trust in February 2003, based on year-end 2002 reserves the NAV was determined to be $8.91 per Trust Unit based on a 5 percent discount rate. Since that time, including the January 15, 2008 distribution, the Trust has distributed $11.92 per Trust Unit. Despite having distributed $3.01 per Trust Unit more in cash distributions than the initial NAV, the NAV as at December 31, 2007 had increased to $10.50 per Trust Unit using a 5 percent discount rate.
FINDING, DEVELOPMENT AND ACQUISITION (“FD&A”) COSTS
Under NI 51-101, the methodology to be used to calculate FD&A costs includes incorporating changes in future development capital (“FDC”) required to bring the proved undeveloped and probable reserves to production. For continuity, PET has presented herein FD&A costs calculated both excluding and including FDC.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change in estimated future development costs during that year generally will not reflect total finding and development costs related to reserves additions for that year. Consequently PET has also presented three-year average FD&A cost information.
FUTURE DEVELOPMENT CAPITAL
NI 51-101 requires that FD&A costs be calculated including changes in future development capital (“FDC”). Changes in forecast FDC occur annually as a result of development activities, acquisitions and disposition activities and capital cost estimates that reflect the independent evaluator’s best estimate of what it will cost to bring the proved undeveloped and probable reserves on production.
FD&A Costs – Company Interest Reserves —————————————————————————- —————————————————————————- Proved and Proved Probable —————————————————————————- FD&A Costs Excluding Future Development Capital Total Capital Expenditures Including Net Acquisitions – $MM(1) (unaudited) $564.1 $564.1 Increase in book value of undeveloped land – $MM (unaudited) $(59.1) $(59.1) FD&A Capital Expenditures Including Net Acquisitions- $MM (unaudited) $505.0 $505.0 Reserve Additions Including Net Acquisitions – Bcf 180.0 310.7 Finding Development and Acquisition Cost – $/Mcf $2.81 $1.63 Three Year Average FD&A Cost – $/Mcf $3.57 $2.36 FD&A Costs Including Future Development Capital Total Capital Expenditures Including Net Acquisitions – $MM(1) (unaudited) $564.1 $564.1 Increase in book value of undeveloped land – $MM (unaudited) $(59.1) $(59.1) FD&A Capital Expenditures Including Net Acquisitions- $MM (unaudited) $505.0 $505.0 Total Change in FDC – $MM $81.2 $291.2 Total FD&A Capital Including Change in FDC – $MM $586.2 $796.2 Reserve Additions Including Net Acquisitions – Bcf 180.0 310.7 Finding Development and Acquisition Cost Including FDC – $/Mcf $3.26 $2.56 Three Year Average FD&A Cost Including FDC – $/Mcf $3.92 $3.08 —————————————————————————- —————————————————————————- Historic Company Interest Proved FD&A Costs —————————————————————————- —————————————————————————- 2007 2006 2005 2004 —————————————————————————- Annual FD&A, Excluding FDC 2.81 6.37 4.07 4.04 Three Year Average FD&A, Excluding FDC 3.57 —————————————————————————- Annual FD&A, Including FDC 3.26 6.38 4.34 4.09 Three Year Average FD&A, Including FDC 3.92 —————————————————————————- —————————————————————————- Historic Company Interest Proved and Probable FD&A Costs —————————————————————————- —————————————————————————- 2007 2006 2005 2004 —————————————————————————- Annual FD&A, Excluding FDC 1.63 7.03 3.15 3.16 Three Year Average FD&A, Excluding FDC 2.36 —————————————————————————- Annual FD&A, Including FDC 2.56 7.08 3.41 3.21 Three Year Average FD&A, Including FDC 3.08 —————————————————————————- —————————————————————————-
Forward-looking Information
This news release contains forward-looking information. Implicit in this information, particularly in respect of cash distributions, are assumptions regarding natural gas prices, production, royalties and expenses which, although considered reasonable by PET at the time of preparation, may prove to be incorrect. These forward-looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. Actual results could differ materially as a result of changes in PET’s plans, changes in commodity prices, general economic, market, regulatory and business conditions as well as production, development and operating performance and other risks associated with oil and gas operations. There is no guarantee by PET that actual results achieved will be the same as those forecast herein.
Non-GAAP Measures
This news release contains financial measures that may not be calculated in accordance with generally accepted accounting principles in Canada (“GAAP”). Readers are referred to advisories and further discussion on non-GAAP measures contained in the “Significant Accounting Policies and Non-GAAP Measures” section of the Trust’s Management’s Discussion and Analysis.
Mcf equivalent (Mcfe) may be misleading, particularly if used in isolation. In accordance with National Instrument 51-101 (“NI 51-101″), a Mcfe conversion ratio for oil of 1 Bbl: 6 Mcf has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead.
Paramount Energy Trust is a natural gas-focused Canadian energy trust. PET’s Trust Units and Convertible Debentures are listed on the Toronto Stock Exchange under the symbols “PMT.UN”, “PMT.DB”, “PMT.DB.A”, “PMT.DB.B”, and “PMT.DB.C” respectively. Further information with respect to PET can be found at its website at www.paramountenergy.com.
The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.
Contacts: Paramount Energy Trust Susan L. Riddell Rose President and Chief Executive Officer (403) 269-4400 Paramount Energy Trust Cameron R. Sebastian Vice President, Finance and Chief Financial Officer (403) 269-4400 Paramount Energy Trust Sue M. Showers Investor Relations and Communications Advisor (403) 269-4400 (403) 269-4444 (FAX) Paramount Energy Operating Corp, administrator of Paramount Energy Trust Suite 3200, 605 – 5 Avenue SW Calgary, Alberta T2P 3H5 Email: info@paramountenergy.com Website: www.paramountenergy.com
SOURCE: Paramount Energy Trust