Daylight Resources Trust Reports Third Quarter 2009 Financial and Operating Results- Significant Operational Results Validate Resource Play Strategy on Multiple Fronts
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CALGARY, ALBERTA--(Marketwire - Nov. 4, 2009) - Daylight Resources Trust (TSX: DAY.UN)
MESSAGE TO UNITHOLDERS
Daylight Resources Trust ("Daylight" the "Trust" or the "Company") is pleased to report financial and operating results for the three and nine months ended September 30, 2009 ("Q3 2009" and "YTD 2009" respectively).
Record production volumes of 23,502 barrels of oil equivalent ("boe") per day highlight another strong quarter for Daylight representing year over year production growth of 8% which was net of approximately 2,500 boe per day shut-in during the period due to low natural gas prices. Daylight expects to return these shut-in volumes to production prior to the end of 2009 in conjunction with improved natural gas prices. In addition, Daylight elected to defer the majority of our Q3 2009 natural gas capital program to Q4 2009 with an expectation of improved prices. Increased production volumes delivered during Q3 2009 combined with stronger light oil, heavy oil and natural gas liquids ("NGLs") prices, reduced royalties and the continued strength of our hedging program resulted in a quarter over quarter increase in the Company's funds from operations to over $50 million. Daylight continues to benefit from our reliable operational results and high value hedging program, delivering a payout ratio of 58% for Q3 2009 and 54% YTD 2009. Based on our positive results and solid outlook, the Trust has declared that our distributions will continue at $0.08 per unit per month for Q4 2009.
During Q3 2009 Daylight announced the acquisition of Highpine Oil & Gas Limited ("Highpine"). This acquisition delivers on a number of strategic objectives of the Company: re-balancing our production base towards light oil, adding a strong future source of cash flow to fund growth operations on our resource play assets and providing Daylight with a significant land base in the exciting new Cardium oil resource play area of central Alberta. Including the addition of the Highpine assets, Daylight expects to meet our previously announced Q4 2009 production guidance of 38,000 boe per day.
The Highpine acquisition represents a significant milestone in Daylight's maturation from a suite of trust type assets to a growing intermediate sized producer. Daylight has expended considerable time and resources during the last three years accumulating and proving up multiple resource play assets in our core areas, focused on the premier Deep Basin gas producing region of Western Canada. The addition of a developing Cardium oil resource play in Pembina places Daylight at the forefront of emerging intermediate producers. After analyzing various restructuring options available to income trusts and considering our long-term growth oriented asset base, Daylight intends to propose to our unitholders the conversion of Daylight to a dividend paying corporation during 2010. The timing of the conversion is dependent upon a number of factors; however, we expect to propose conversion no later than May 2010 at our Annual General Meeting.
Daylight has focused on adding to our core areas in the Deep Basin of Alberta and Northeast British Columbia due to the breadth and depth of resource play type opportunities available there. The following provides an overview of recent operational results, both from Daylight and our industry peers, and a summary of how these results impact Daylight's significant opportunity base across the Deep Basin:
Pembina: Cardium Oil Resource Play - Daylight currently has over 100 net sections of land with Cardium rights in the key Pembina area of Alberta.
- The Cardium oil zone has produced over 1.0 billion barrels of oil in Pembina since the 1950s utilizing conventional technologies. Several operators, including Daylight, are beginning to test the area for unconventional resource development on new trends that have been identified adjacent to the older conventional developments.
- Recent advancements in unconventional horizontal drilling and multi-stage fracture completion technologies have shown promising results in the Pembina area for further development of the Cardium as an oil resource play. An offsetting operator recently announced a 48 hour flow test on a new horizontal Cardium oil well with 270 boe per day produced adjacent to a large contiguous block of high working interest Daylight Cardium lands. Internal Daylight geological estimates indicate between 8 million and 12 million barrels of oil in place per section in this area of Pembina.
- Thirty miles to the northeast of this test well, Daylight has another large contiguous block of Cardium rights. Daylight has now drilled and cased our first horizontal Cardium oil well in Pembina within this second block of lands. This well is currently being completed with multiple fractures across the horizontal interval. Daylight plans to bring this 100% working interest well on production in December. Recent results in the Pembina area are very encouraging and this play has the potential to add a significant number of horizontal Cardium oil locations to our 2010 capital program.
Elmworth and Northeast British Columbia: Cadomin, Cretaceous, Montney and Nikanassin Natural Gas Resource Plays - Total Daylight lands on this trend are now over 200 net sections.
- Daylight was successful at a Q4 2009 land sale in Northeast British Columbia, adding 53 gross and net sections of land on trend with our resource play developments in Elmworth.
- Daylight has previously disclosed internal estimates that indicate, excluding the newly acquired lands, these opportunities combine to expose Daylight to an unrisked opportunity to develop 4 Tcf of natural gas on our Elmworth land base.
- Daylight is currently undertaking drilling and completion operations on two follow-up wells to our first two Nikanassin vertical wells in Elmworth. The first two wells drilled had average sand thickness of over 100 metres and produced at initial rates of between 2 and 3 mmcf per day. Daylight plans to drill our initial horizontal well into the Nikanassin during Q1 2010.
- Daylight will continue our Cadomin and uphole Cretaceous resource play development in Elmworth during 2010. Daylight has over 20 horizontal Cadomin and uphole Cretaceous wells on production in the Elmworth area. With the advancement of our Nikanassin program during 2009 and early 2010, we will establish an optimal development strategy for the Cadomin in conjunction with the Nikanassin.
- Daylight is currently drilling our first Montney horizontal well in the Wapiti area, just east of Elmworth. This well is on trend with a competitor horizontal well that had an initial production rate of 2.9 mmcf per day. Daylight has 24 net sections of land on trend with this initial well available for potential follow-up drilling.
West Central Alberta: Bluesky, Wilrich and other Cretaceous opportunities - Daylight's initial core producing area is our West Central property. West Central includes regions such as Kaybob, Pine Creek and Obed that have been proven natural gas exploration and development areas for decades. This region has been identified by Daylight and others as an excellent area for utilizing horizontal multi-stage fracture development technologies in multiple play types.
- Bluesky - Daylight has been an active developer of conventional Bluesky natural gas in West Central for several years. We have participated in five non-operated unconventional horizontal multi-stage fractured wells with partners, testing natural gas beyond the periphery of the original conventional development. The first two wells came on production at initial rates of 2.7 and 3.8 mmcf per day with NGL yield rates of over 40 bbls per mmcf. Two of the follow-up wells are not yet on production but tested at double the test rates of the initial two wells, the final well is awaiting completion. Daylight has 17 net sections of lands with Bluesky rights in the West Central Bluesky fairway and we commenced drilling the first well of our seven well Daylight operated Bluesky program during Q3 2009.
- Marlboro Wilrich - Daylight has participated in the drilling of three horizontal multi-stage fractured wells into the Wilrich zone. The first well drilled had an initial production rate in excess of 4 mmcf per day and has produced 0.5 Bcf in its first five months of production. Daylight has subsequently participated in two additional Wilrich wells with similar production results. Daylight has over 24 net sections of prospective land with Wilrich rights in the West Central area.
- Obed Cretaceous - Daylight has continued to pursue our successful program in the Cretaceous at Obed. Our most recent well was tied in during late September 2009 and at the end of October was still producing in excess of 10 mmcf per day. Daylight has 11 net sections of Cretaceous rights in the Obed area.
- Cardium Gas - Daylight recently participated in a horizontal well testing unconventional drilling and completion technology for Cardium gas development. The well came on production at an initial rate of over 4 mmcf per day and 180 bbl per day of NGLs. Daylight has a 40% working interest in this well with an additional three net sections of prospective lands adjacent to this discovery.
DAYLIGHT RESOURCES TRUST - HIGHLIGHTS
Operations
- Recorded Q3 2009 production volumes of 23,502 boe per day. The Trust maintains our Q4 production guidance of 38,000 boe per day based on the closing of the Highpine transaction on October 8, 2009.
- Capital expenditures of $10.6 million during Q3 2009. Daylight plans capital spending of approximately $75 million in Q4 2009 in order to accelerate development on several of the projects detailed previously and we maintain our $160 million 2009 capital budget guidance.
Financials
- Funds from operations increased to $50.2 million during Q3 2009 from $48.5 million in Q2 2009 due to higher production volumes and increases in oil and NGL prices.
- Royalty rates for Q3 2009 decreased to 15.9% of revenue compared to 16.9% of revenue in Q2 2009.
- Recognized a realized gain of $32.3 million on derivative contracts in Q3 2009 compared to a realized gain of $30.0 million in Q2 2009.
- Trust declared a continuation of our $0.08 per unit per month distribution for Q4 2009.
Balance Sheet
- Maintained our strong financial position with a net debt to annualized funds from operations ratio of 1.0 times.
- Bank debt increased to $164.2 million at the end of Q3 2009 from $161.0 million at the end of Q2 2009. Subsequent to the end of the quarter, with the addition of the Highpine assets, Daylight's bank credit facility was increased to $500 million with approximately $250 million drawn at closing of the Highpine acquisition. This provides Daylight significant flexibility to actively pursue strategic opportunities.
THIRD QUARTER FINANCIAL AND OPERATIONAL RESULTS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial
(CDN$ thousands,
except unit, per
unit and
operational Q3 Q2 Q3 YTD YTD
data) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Petroleum and
natural gas
revenues $ 66,100 $ 66,649 $ 145,269 $ 204,642 $ 410,426
----------------------------------------------------------------------------
Operating
netback 60,252 58,383 81,808 174,951 238,154
----------------------------------------------------------------------------
Funds from
operations 50,245 48,459 78,646 143,599 214,345
Per unit
- Basic 0.41 0.45 0.91 1.34 2.63
- Diluted 0.39 0.42 0.84 1.25 2.37
----------------------------------------------------------------------------
Cash
distributions
declared 29,385 26,254 33,684 77,296 81,824
Per unit 0.24 0.24 0.39 0.72 0.99
Payout ratio 58% 54% 43% 54% 38%
----------------------------------------------------------------------------
Capital
expenditures 10,613 15,803 45,657 85,829 127,153
----------------------------------------------------------------------------
Units
outstanding
(000s)
Basic 122,437 122,434 86,299 122,437 86,299
Diluted 138,499 138,457 94,295 138,499 94,295
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operational
----------------------------------------------------------------------------
Average daily
production
Natural gas
(mcf/d) 100,250 96,173 81,798 96,062 74,869
----------------------------------------------------------------------------
Light oil
(bbls/d) 3,421 3,596 4,864 3,649 4,979
Heavy oil
(bbls/d) 2,096 2,141 2,179 2,118 2,205
NGLs (bbls/d) 1,277 1,281 1,106 1,345 1,109
----------------------------------------------------------------------------
Oil & NGLs
(bbls/d) 6,794 7,018 8,149 7,112 8,293
----------------------------------------------------------------------------
Combined
(boe/d) 23,502 23,047 21,782 23,122 20,771
----------------------------------------------------------------------------
Average prices
received
----------------------------------------------------------------------------
Natural gas
($/mcf) $ 3.05 $ 3.53 $ 8.54 $ 3.90 $ 8.90
----------------------------------------------------------------------------
Light oil
($/bbl) 67.58 60.54 116.11 57.65 109.14
Heavy oil
($/bbl) 59.39 56.16 99.43 51.10 89.15
NGLs ($/bbl) 45.08 42.75 89.43 42.06 82.88
----------------------------------------------------------------------------
Oil & NGLs
($/bbl) $ 60.82 $ 55.96 $ 108.03 $ 52.75 $ 100.32
----------------------------------------------------------------------------
Combined
($/boe) $ 30.58 $ 31.78 $ 72.50 $ 32.42 $ 72.12
----------------------------------------------------------------------------
$ per boe
Petroleum and
natural gas
revenues $ 30.58 $ 31.78 $ 72.50 $ 32.42 $ 72.12
Royalties (4.87) (5.36) (14.05) (5.68) (13.96)
Realized gain
(loss) on
derivative
contracts 14.93 14.33 (4.61) 13.88 (3.29)
Operating
expenses (11.65) (11.86) (11.95) (11.80) (12.00)
Transportation
expenses (1.12) (1.05) (1.06) (1.10) (1.02)
----------------------------------------------------------------------------
Operating
netback $ 27.87 $ 27.84 $ 40.82 $ 27.72 $ 41.85
G&A - cash
charge (2.28) (2.44) (2.27) (2.68) (2.18)
Cash financial
charges (2.35) (2.29) (2.31) (2.28) (3.06)
Provision for
non-recoverable
accounts
receivable - - (0.90) - (0.32)
Other income(1) - - 3.90 - 1.37
----------------------------------------------------------------------------
Funds from
operations $ 23.24 $ 23.11 $ 39.24 $ 22.76 $ 37.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Non-recurring termination fee of $9.0 million relates to termination of
arrangement with Cadence Energy Inc., less transaction costs of $1.2
million.
Per boe amounts may not add exactly due to rounding
THIRD QUARTER FINANCIAL RESULTS
Operating Netback
- Operating netback of $27.87 per boe for Q3 2009 compared to $27.84 per boe for Q2 2009.
- Operating expenses improved to $11.65 per boe for Q3 2009 from $11.86 per boe for Q2 2009. Daylight expects its operating costs to be approximately $11.50 per boe for Q4 2009.
- Overall royalty rates decreased to 15.9% of revenue in Q3 2009 versus 16.9% of revenue in Q2 2009.
Funds from Operations
- Funds from operations for Q3 2009 increased to $50.2 million from $48.5 million for Q2 2009.
- Increased funds from operations for Q3 2009 were generated by increased production volumes combined with higher oil and NGL prices.
- Average price received for natural gas decreased to $3.05 per mcf from $3.53 per mcf for Q3 2009.
- Average price received for light oil improved to $67.58 per bbl for Q3 2009, a 12% increase over Q2 2009.
- Average price received for heavy oil improved to $59.39 per bbl for Q3 2009, an increase of 6% over Q2 2009.
2009 OUTLOOK
Capital Expenditures
- 2009 capital expenditure budget has been maintained at $160 million to be invested in our inventory of repeatable, low risk exploitation projects.
- Capital spending of approximately $75 million for the remainder of the year will focus primarily on horizontal resource play gas wells targeting the Bluesky in West Central, the Montney formation in Wapiti and Cardium oil in Pembina. Moving forward into 2010, the Company will spud our first horizontal Nikanassin test in Elmworth and also pursue additional vertical conventional natural gas opportunities.
Tax Pools and Safe Harbour
- Daylight and its subsidiaries have tax pools of over $1.4 billion upon closing of the Highpine transaction on October 8, 2009 which are available to shelter significant cash flow from income tax in current periods and well beyond our planned proposal to unitholders to convert to a dividend paying corporation during 2010.
- Current safe harbour capacity for the issuance of approximately $350 million of new equity provides significant flexibility to execute on strategic acquisition opportunities as they arise.
Daylight is also pleased to announce that Mr. Gordon Stollery has been appointed to the Board of Directors of Daylight. Mr. Stollery is a veteran oil executive who has been involved in the founding and building of a number of successful energy companies including Morrison Petroleums Ltd. and most recently was on the Board of Directors of Highpine.
Daylight is a growing intermediate oil and natural gas producing company with a high quality suite of resource play assets in Western Canada. Our highly focused team utilizes our technical expertise in exploitation, development and acquisitions to create long-term value for our unitholders. Our team has developed a multi-year inventory of repeatable, low risk exploitation resource play projects with substantial potential reserve additions on assets we currently own and control in the premier Deep Basin area of Alberta.
Daylight has approximately 174 million trust units currently outstanding which trade on the TSX under the symbol DAY.UN. Daylight Series A, Series B, and Series C convertible debentures trade on the TSX under the symbols DAY.DB, DAY.DB.B and DAY.DB.C respectively.
An updated corporate presentation is available on Daylight's website at www.daylightenergy.ca.
Signed:
Anthony Lambert, President & CEO
November 4, 2009
MANAGEMENT'S DISCUSSION AND ANALYSIS
This Management's Discussion & Analysis ("MD&A") is dated November 4, 2009 and should be read in conjunction with the accompanying unaudited interim consolidated financial statements and notes for the three and nine months ended September 30, 2009 and 2008 as well as the MD&A and audited consolidated financial statements and notes for the years ended December 31, 2008 and 2007. The consolidated financial statements and other financial data presented have been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The following MD&A compares the results of the three months ended September 30, 2009 ("Q3 2009") to the three months ended June 30, 2009 ("Q2 2009") and to the three months ended September 30, 2008 ("Q3 2008"). This MD&A also compares the results of the nine months ended September 30, 2009 ("YTD 2009") to the nine months ended September 30, 2008 ("YTD 2008"). All references are to Canadian dollars unless otherwise indicated.
NON-GAAP MEASURES
Daylight Resources Trust ("Daylight" or the "Trust") utilizes the following terms for measurement within the MD&A that do not have standardized prescribed meaning under GAAP and these measurements may not be comparable with the calculation of similar measurements of other entities.
"Funds from operations" and "funds from operations per unit" are terms utilized by Daylight to evaluate operating performance and assess leverage. Daylight considers funds from operations to be an important measure of Daylight's ability to generate the funds necessary to pay distributions, repay debt and finance capital expenditures. Funds from operations does not represent net income for the period nor should it be viewed as an alternative to net income or other measures of financial performance calculated in accordance with GAAP. All references to funds from operations throughout the MD&A are based on cash provided by operating activities before the change in non-cash operating working capital and asset retirement expenditures since Daylight believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such these items are not useful for evaluating Daylight's operating performance. A reconciliation of cash provided by operating activities to funds from operations follows.
----------------------------------------------------------------------------
(000s) Q3 Q2 Q3 YTD YTD
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by
operating activities $ 44,054 $ 49,198 $ 97,799 $ 140,681 $ 212,343
Change in non-cash
operating working
capital 2,684 (1,993) (20,342) (2,854) (468)
Asset retirement
expenditures 3,507 1,254 1,189 5,772 2,470
----------------------------------------------------------------------------
Funds from operations $ 50,245 $ 48,459 $ 78,646 $ 143,599 $ 214,345
----------------------------------------------------------------------------
----------------------------------------------------------------------------
"Payout ratio" is a term utilized to evaluate financial flexibility and the capacity to fund distributions. Payout ratio is defined on a percentage basis as distributions declared divided by funds from operations.
"Operating netback" is a term utilized by Daylight to evaluate the operating performance of petroleum and natural gas assets. The term operating netback is defined as petroleum and natural gas revenues less royalties, realized gain (loss) on derivative contracts, operating and transportation expenses.
"boe" is a term utilized by Daylight in relation to reserves or production to combine the volumetric measures of natural gas, light oil, heavy oil and natural gas liquids ("NGLs") to a common "barrel of oil equivalent" term of measurement. Natural gas volumes have been converted at the ratio of 6,000 cubic feet of natural gas to one boe and this conversion ratio is based upon an energy equivalent conversion method primarily applicable at the burner tip and does not represent value equivalence at the wellhead. Light oil, heavy oil and NGLs have been converted at the ratio of one barrel of these liquids to one boe. Use of the terms boe and amounts per boe without reference to the underlying commodity may be misleading.
FORWARD-LOOKING STATEMENTS
Certain statements contained within this MD&A, and in certain documents incorporated by reference into this document, constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "budget", "plan", "continue", "estimate", "expect", "forecast", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We believe the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this MD&A should not be unduly relied upon. These statements speak only as of the date of this MD&A or as of the date specified in the documents incorporated by reference into this MD&A, as the case may be.
This MD&A, and the documents incorporated by reference, contain forward-looking statements pertaining to the following:
- the performance characteristics of our oil and natural gas properties;
- the size of our oil, natural gas liquids and natural gas reserves and production levels;
- estimates of future cash flow and distributions;
- projections of market prices and costs and the related sensitivities to distributions;
- drilling plans and timing of drilling, recompletion and tie-in of wells;
- weighting of production between different commodities;
- commodity prices, exchange rates and interest rates;
- expected levels of royalty rates, operating costs, general and administrative costs, costs of services and other costs and expenses;
- capital expenditure programs and other expenditures and the timing and method of financing thereof;
- supply of and demand for oil, natural gas liquids and natural gas;
- expectations regarding our ability to raise capital and to continually add to reserves through acquisitions and development;
- the existence, operation and strategy of our commodity price risk management program;
- the approximate and maximum amount of forward sales and hedging to be employed by us;
- our acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;
- our ability to grow or sustain production and reserves through prudent management;
- the emergence of accretive growth opportunities and continued access to capital markets;
- our future operating and financial results;
- schedules and timing of certain projects and our strategy for future growth; and
- treatment under governmental and other regulatory regimes and tax, environmental and other laws.
In particular, this MD&A contains the following forward-looking statements pertaining to the following: - production volumes; - timing of cash flows; - future oil and gas prices; - operating costs; - royalty rates;
- future development, exploration, and acquisition and development activities and related expenditures;
- future liquidity and future financial capacity;
- distributions to unitholders;
- future tax treatment of the Trust; and
- future structure of the Trust and its subsidiaries.
With respect to forward-looking statements contained in this MD&A and the documents incorporated by reference herein, we have made assumptions regarding, among other things:
- future oil and natural gas prices and differentials between light, medium and heavy oil prices;
- the continued availability of capital, undeveloped lands and skilled personnel;
- the costs of expanding our property holdings;
- the ability to obtain equipment in a timely manner to carry out exploration, development and exploitation activities;
- the ability to obtain financing on acceptable terms;
- the ability to add production and reserves through exploration, development and exploitation activities; and
- the continuation of the current tax and regulatory regime and other assumptions contained in this MD&A and the documents incorporated by reference herein.
The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A and the documents incorporated by reference into this document:
- volatility in market prices for oil, natural gas liquids and natural gas;
- counterparty credit risk;
- access to capital;
- changes or fluctuations in oil, natural gas liquids and natural gas production levels;
- liabilities inherent in oil and natural gas operations;
- adverse regulatory rulings, orders and decisions;
- attracting, retaining and motivating skilled personnel;
- uncertainties associated with estimating oil and natural gas reserves;
- competition for, among other things, capital, acquisitions of reserves, undeveloped lands, and services;
- incorrect assessments of the value of acquisitions and targeted exploration and development assets;
- fluctuations in foreign exchange or interest rates;
- stock market volatility, market valuations and the market value of the securities of Daylight;
- failure to realize the anticipated benefits of acquisitions;
- actions by governmental or regulatory authorities including changes in royalty structures and programs and income tax laws (including those relating to mutual fund trusts or investment eligibility) or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts;
- limitations on insurance;
- changes in environmental or other legislation applicable to our operations, and our ability to comply with current and future environmental and other laws;
- geological, technical, drilling and processing problems and other difficulties in producing oil, natural gas liquids and natural gas reserves; and
- the other factors discussed under "Risks and Uncertainties" in the annual Management's Discussion and Analysis.
Statements relating to "reserves" or "resources" are by their nature deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future.
Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this MD&A and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities law.
HIGHLIGHTS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial
(CDN$ thousands,
except unit,
per unit and Q3 Q2 Q3 YTD YTD
operational data) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Petroleum and natural
gas revenues $ 66,100 $ 66,649 $145,269 $204,642 $410,426
Royalties (10,527) (11,238) (28,149) (35,876) (79,450)
Realized gain (loss) on
derivative contracts 32,282 30,048 (9,237) 87,615 (18,744)
Operating expenses (25,179) (24,875) (23,943) (74,495) (68,299)
Transportation expenses (2,424) (2,201) (2,132) (6,935) (5,779)
----------------------------------------------------------------------------
Operating netback 60,252 58,383 81,808 174,951 238,154
G&A - cash charge (4,934) (5,117) (4,542) (16,936) (12,396)
Cash financial charges (5,073) (4,807) (4,626) (14,416) (17,419)
Provision for
non-recoverable
accounts receivable - - (1,800) - (1,800)
Other income(1) - - 7,806 - 7,806
----------------------------------------------------------------------------
Funds from operations 50,245 48,459 78,646 143,599 214,345
Per unit - Basic 0.41 0.45 0.91 1.34 2.63
- Diluted 0.39 0.42 0.84 1.25 2.37
----------------------------------------------------------------------------
Cash provided by
operating activities 44,054 49,198 97,799 140,681 212,343
----------------------------------------------------------------------------
Net income (loss) (7,244) (14,543) 69,692 (15,716) 116,095
Per unit
- Basic (0.06) (0.14) 0.81 (0.15) 1.42
- Diluted (0.06) (0.14) 0.76 (0.15) 1.33
----------------------------------------------------------------------------
Cash distributions
declared 29,385 26,254 33,684 77,296 81,824
Per unit 0.24 0.24 0.39 0.72 0.99
Payout ratio 58% 54% 43% 54% 38%
----------------------------------------------------------------------------
Capital expenditures 10,613 15,803 45,657 85,829 127,153
Capital divestitures - - (87,695) - (87,695)
Corporate acquisitions - 123,827 36,433 123,827 36,433
----------------------------------------------------------------------------
Market value of
investments 4,143 2,599 9,987 4,143 9,987
----------------------------------------------------------------------------
Bank debt 164,172 160,983 199,282 164,172 199,282
Working capital
deficiency (2) 31,298 40,986 37,200 31,298 37,200
----------------------------------------------------------------------------
Convertible debentures 117,217 116,525 54,180 117,217 54,180
----------------------------------------------------------------------------
Total assets 1,097,686 1,153,128 915,364 1,097,686 915,364
----------------------------------------------------------------------------
Units outstanding (000s)
- Basic 122,437 122,434 86,299 122,437 86,299
- Diluted 138,499 138,457 94,295 138,499 94,295
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operational (Per boe amounts may not add exactly due to rounding)
----------------------------------------------------------------------------
Average daily production
----------------------------------------------------------------------------
Natural gas (mcf/d) 100,250 96,173 81,798 96,062 74,869
----------------------------------------------------------------------------
Light oil (bbls/d) 3,421 3,596 4,864 3,649 4,979
Heavy oil (bbls/d) 2,096 2,141 2,179 2,118 2,205
NGLs (bbls/d) 1,277 1,281 1,106 1,345 1,109
----------------------------------------------------------------------------
Oil & NGLs (bbls/d) 6,794 7,018 8,149 7,112 8,293
----------------------------------------------------------------------------
Combined (boe/d) 23,502 23,047 21,782 23,122 20,771
----------------------------------------------------------------------------
Average prices received
----------------------------------------------------------------------------
Natural gas ($/mcf) $ 3.05 $ 3.53 $ 8.54 $ 3.90 $ 8.90
----------------------------------------------------------------------------
Light oil ($/bbl) 67.58 60.54 116.11 57.65 109.14
Heavy oil ($/bbl) 59.39 56.16 99.43 51.10 89.15
NGLs ($/bbl) 45.08 42.75 89.43 42.06 82.88
----------------------------------------------------------------------------
Oil & NGLs ($/bbl) $ 60.82 $ 55.96 $ 108.03 $ 52.75 $ 100.32
----------------------------------------------------------------------------
Combined ($/boe) $ 30.58 $ 31.78 $ 72.50 $ 32.42 $ 72.12
----------------------------------------------------------------------------
$ per boe
Petroleum and natural
gas revenues $ 30.58 $ 31.78 $ 72.50 $ 32.42 $ 72.12
Royalties (4.87) (5.36) (14.05) (5.68) (13.96)
Realized gain (loss)
on derivative contracts 14.93 14.33 (4.61) 13.88 (3.29)
Operating expenses (11.65) (11.86) (11.95) (11.80) (12.00)
Transportation expenses (1.12) (1.05) (1.06) (1.10) (1.02)
----------------------------------------------------------------------------
Operating netback $ 27.87 $ 27.84 $ 40.82 $ 27.72 $ 41.85
G&A - cash charge (2.28) (2.44) (2.27) (2.68) (2.18)
Cash financial charges (2.35) (2.29) (2.31) (2.28) (3.06)
Provision for
non-recoverable
accounts receivable - - (0.90) - (0.32)
Other income(1) - - 3.90 - 1.37
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Funds from operations $ 23.24 $ 23.11 $ 39.24 $ 22.76 $ 37.66
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Wells drilled -
gross (net) 17 (10.4) 2 (0.1) 15 (7.0) 39 (16.6) 40 (18.1)
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(1) Non-recurring termination fee of $9.0 million relates to termination of
arrangement with Cadence Energy Inc., less transaction costs of $1.2
million.
(2) Excludes unrealized gain (loss) on derivative contracts and future
income tax liability.
RESULTS OF OPERATIONS
Overview
Daylight is a growing intermediate oil and natural gas producing company with a high quality suite of assets in Western Canada. Our highly focused team utilizes our technical expertise in exploitation, development and acquisitions to create long-term value for our unitholders. Our team has developed a multi-year inventory of repeatable, low risk exploitation resource play projects with substantial potential reserve additions on assets we currently own and control in the premier Deep Basin area of Alberta. Daylight's trust units, 8.5% Convertible Debentures Series A, 8.5% Convertible Debentures Series B, and 10.0% Convertible Debentures Series C trade on the Toronto Stock Exchange ("TSX") with the symbols DAY.UN, DAY.DB, DAY.DB.B, and DAY.DB.C respectively.
Although the first nine months of 2009 have been challenging in the oil and gas sector with continued low natural gas prices and volatility in the global economy, Daylight has remained focused on its long-term plan of acquiring and developing high quality assets in its core areas. Daylight has maintained its strong financial position with a net debt to annualized funds from operations ratio of 1.0 times, significant available capacity on its bank credit facilities, and an extensive portfolio of internal development prospects. The maintenance of a healthy balance sheet has provided Daylight the flexibility to execute on opportunities throughout the year. On October 8, 2009, Daylight closed its acquisition of Highpine Oil & Gas Limited ("Highpine") which is expected to increase Daylight's production to approximately 38,000 boe per day for the fourth quarter 2009 from current quarter production of 23,502 boe per day. Daylight also acquired Intrepid Energy Corporation ("Intrepid") on June 5, 2009 (see "Capital Expenditures, Acquisitions and Divestitures"). On May 7, 2009, the Trust issued 24,630,000 trust units for gross proceeds of $172 million (see "Liquidity and Capital Resources").
Based on analysis of restructuring options available to income trusts, tax considerations and long-term plans for the organization, Daylight intends to propose to unitholders that Daylight convert to a dividend paying corporation by not later than May 2010 at our Annual General Meeting. The timing of conversion is dependent upon a number of factors including, but not limited to, Daylight's current safe harbour capacity of approximately $350 million. Throughout the remainder of 2009 and into 2010, Daylight will continue to pursue strategic opportunities as they arise, capitalize on the organization's extensive portfolio of internal development prospects and maintain focus on preserving financial flexibility.
Production
Daylight's total production volumes for Q3 2009 averaged 23,502 boe per day, a 2% increase from Q2 2009, as Daylight shut in approximately 2,500 boe per day of natural gas weighted production during the quarter due to low natural gas prices. As natural gas prices continue to improve during the fourth quarter 2009, it is anticipated these volumes will be brought back on stream prior to the end of 2009. Q3 2009 production was comprised of 100,250 mcf per day of natural gas, 3,421 bbls per day of light oil, 2,096 bbls per day of heavy oil and 1,277 bbls per day of NGLs. Production for Q3 2009 increased 8% from Q3 2008 due to our successful capital expenditure program coupled with our recent corporate and property acquisitions. See the "Capital Expenditures, Acquisitions and Divestitures" section of this MD&A for additional information on the acquisitions of Intrepid, Athlone Energy Ltd. ("Athlone"), West Central properties and Elmworth properties. Production for YTD 2009 was 23,122 boe per day, an increase of 11% from YTD 2008.
On October 8, 2009, Daylight acquired Highpine. With the addition of the Highpine volumes, offset by a reduction in natural gas volumes shut in due to low prices, Daylight expects production to average approximately 38,000 boe per day for the fourth quarter 2009, resulting in average production of approximately 26,800 boe per day for 2009. Daylight's 2009 production guidance is based on the investment of $160 million in our 2009 internal capital program.
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Q3 Q2 Q3 YTD YTD
2009 2009 2008 2009 2008
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Natural gas (mcf/d) 100,250 96,173 81,798 96,062 74,869
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Light oil (bbls/d) 3,421 3,596 4,864 3,649 4,979
Heavy oil (bbls/d) 2,096 2,141 2,179 2,118 2,205
NGLs (bbls/d) 1,277 1,281 1,106 1,345 1,109
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Combined oil & NGLs (bbls/d) 6,794 7,018 8,149 7,112 8,293
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Combined all products (boe/d) 23,502 23,047 21,782 23,122 20,771
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Production addition activities for calendar 2009 are focused on the following:
- Peace River Arch properties of Elmworth and Bilbo
- West Central properties of Obed, Pine Creek and Kaybob
- East properties of Wildmere and Pembina
Commodity Prices
Daylight's natural gas prices are influenced by both North American and global supply and demand balances, seasonal changes, storage levels, the Canadian to US dollar exchange rate and transportation capacity constraints. Daylight's realized natural gas price has a high correlation to the daily Alberta benchmark price ("AECO") which provides pricing for natural gas. Daylight markets the majority of its natural gas through a combination of the daily AECO index price and monthly AECO index price contracts with a small portion of its natural gas sold through longer-term contracts with aggregators. As a result, Daylight's realized natural gas price is compared below to AECO index prices.
Daylight's oil prices are significantly influenced by global supply and demand conditions. Daylight's realized light oil price has a high correlation to the US benchmark West Texas Intermediate at Cushing, Oklahoma ("WTI") price and the Canadian to US dollar exchange rate. Canadian light oil prices, including the Edmonton par price, correlate to refinery postings that adjust WTI for the Canadian to US dollar exchange rate as well as transportation costs and quality differentials.
Daylight's realized heavy oil price is lower than its light oil price and the historical correlation with Edmonton par price and Bow River price, a heavy oil benchmark, is not overly strong. Heavy oil requires increased refining and other costs, such as condensate for transportation blending, which reduce the realized price of this product.
NGLs include condensate, pentane, butane and propane. Prices for NGLs have their own market dynamic with a relatively strong correlation to light oil prices for condensate and pentane, while butane and propane trade at varying discounts due to market conditions including supply and demand.
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Market prices Q3 Q2 Q3 YTD YTD
2009 2009 2008 2009 2008
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AECO Index ($Cdn/mcf)
Daily Index $ 2.94 $ 3.45 $ 7.75 $ 3.77 $ 8.62
Monthly Index 3.02 3.66 9.25 4.11 8.58
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WTI ($US/bbl) 68.14 59.69 118.23 57.21 113.54
Edmonton par ($Cdn/bbl) 71.74 66.11 122.74 62.82 115.83
Bow River ($Cdn/bbl) 64.59 61.50 104.95 56.76 95.50
Exchange rate ($Cdn/$US) 0.9116 0.8579 0.9609 0.8580 0.9822
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Daylight prices realized Q3 Q2 Q3 YTD YTD
2009 2009 2008 2009 2008
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Natural gas ($/mcf) $ 3.05 $ 3.53 $ 8.54 $ 3.90 $ 8.90
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Light oil ($/bbl) 67.58 60.54 116.11 57.65 109.14
Heavy oil ($/bbl) 59.39 56.16 99.43 51.10 89.15
NGLs ($/bbl) 45.08 42.75 89.43 42.06 82.88
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Combined oil & NGLs ($/bbl) $ 60.82 $ 55.96 $108.03 $ 52.75 $100.32
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Combined all products ($/boe) $ 30.58 $ 31.78 $ 72.50 $ 32.42 $ 72.12
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Daylight markets its natural gas through contracts based on daily and monthly AECO index pricing with less than 5% sold through longer-term contracts with aggregators. Daylight's natural gas price during Q3 2009 was $3.05 per mcf, a slight premium to the average of the daily and monthly AECO index prices during the period, and a 14% decrease from the Q2 2009 natural gas price of $3.53 per mcf. Daylight's Q3 2009 natural gas price was 64% lower than the Q3 2008 natural gas price of $8.54 per mcf, which is consistent with the decrease to both daily and monthly AECO index prices between these two periods. During Q3 2009, the daily AECO pricing for natural gas ranged from a low of approximately $1.72 per mcf to a high of approximately $4.06 per mcf. Daylight's YTD 2009 natural gas price was $3.90 per mcf, consistent with the daily and monthly AECO index prices during the period and a 56% decrease over the YTD 2008 natural gas price of $8.90 per mcf.
Daylight's Q3 2009 light oil realized $67.58 per bbl, 94% of Edmonton par, while Q2 2009 light oil realized $60.54 per bbl, 92% of Edmonton par, resulting in a quarter over quarter increase of 12%. Daylight's light oil price for Q3 2009 was 42% lower than the Q3 2008 light oil price of $116.11 per bbl, which was 95% of Edmonton par. Daylight's YTD 2009 light oil price of $57.65 per barrel, 92% of Edmonton par, was 47% lower than the YTD 2008 realized light oil price of $109.14 per barrel, 94% of Edmonton par. Changes in the Canadian dollar to US dollar exchange rate affect the Canadian dollar Edmonton par and Daylight's realized light oil price relative to the US dollar WTI, with a higher exchange rate generally reducing Edmonton par and Daylight's realized light oil price relative to WTI and a lower exchange rate generally increasing Edmonton par and Daylight's realized light oil price relative to WTI. The Canadian dollar to US dollar exchange rate for Q3 2009 was 0.9116 which generally put downward movement on Edmonton par and Daylight's realized light oil price in the quarter when compared to Q2 2009 with an exchange rate of 0.8579 and upward movement compared to Q3 2008 with an exchange rate of 0.9609. The Canadian dollar to US dollar exchange rate for YTD 2009 was 0.8580 as compared to 0.9822 for YTD 2008.
For the first nine months of 2008, the Edmonton par price and Bow River price were very strong which resulted in an enhanced price realization by Daylight on its heavy oil production. In Q4 2008 and Q1 2009, the Edmonton par price and Bow River price dropped significantly resulting in lower realized prices by Daylight on its heavy oil production. In Q2 2009 and Q3 2009, the Edmonton par and Bow River prices started to recover, increasing Daylight's realized prices, but not to the levels of the first nine months of 2008. Daylight's heavy oil production is concentrated at two properties, with Wildmere producing approximately 90% of Q3 2009 volumes and Chipman producing the remaining 10%. Daylight's Q3 2009 heavy oil price of $59.39 per bbl, 92% of Bow River, is 6% higher than the Q2 2009 heavy oil price of $56.16 per bbl, 91% of Bow River. Daylight's Q3 2009 heavy oil price was 40% lower than the Q3 2008 heavy oil price of $99.43 per bbl, 95% of Bow River. Daylight's YTD 2009 heavy oil price of $51.10 per barrel, 90% of Bow River, was 43% lower than the YTD 2008 heavy oil price of $89.15 per barrel, 93% of Bow River.
Daylight's combined oil and NGLs price during Q3 2009 was $60.82 per bbl, 9% higher than Q2 2009 and 44% lower than Q3 2008. Daylight's combined oil and NGLs price for YTD 2009 was $52.75 per barrel, a decrease of 47% from the YTD 2008 combined oil and NGLs price of $100.32 per barrel.
The impact of derivative contracts is recorded within Daylight's gain (loss) on financial instruments. As at September 30, 2009, Daylight had derivative contracts in place for a portion of natural gas production volumes for the period October 1, 2009 to August 31, 2010 and a portion of crude oil production volumes from October 1, 2009 through December 31, 2009. Please refer to the "Financial Instruments" section of this MD&A for further details.
Daylight's realized prices are expected to continue to correlate with market prices during the remainder of 2009.
Revenue
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(000s) Q3 Q2 Q3 YTD YTD
2009 2009 2008 2009 2008
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Natural gas $28,088 $30,913 $64,286 $102,214 $182,479
Light oil 21,263 19,812 51,950 57,426 148,899
Heavy oil 11,453 10,941 19,933 29,553 53,863
NGLs 5,296 4,983 9,100 15,449 25,185
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Total $66,100 $66,649 $145,269 $204,642 $410,426
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Revenue for Q3 2009 remained flat with Q2 2009 as a 2% increase in production was offset by a 4% decrease in price on a combined boe basis. Natural gas sales for Q3 2009 were $28.1 million, a decrease of 9% from Q2 2009. Light oil sales for Q3 2009 were $21.3 million, up 7% from Q2 2009. Heavy oil sales for Q3 2009 were $11.5 million, up 5% from Q2 2009, and NGLs sales for Q3 2009 were $5.3 million, up 6% from Q2 2009. Total revenue decreased 54% in Q3 2009 from Q3 2008, consistent with a 58% decrease in the average realized price on a combined boe basis partially offset by an 8% increase in production volumes. For the YTD 2009 period, Daylight realized a 44% decrease in natural gas revenue, a 61% decrease in light oil revenue, a 45% decrease in heavy oil revenue, a 39% decrease in NGL revenue, and a 50% decrease in total revenue over the YTD 2008 period.
Royalties
Royalty payments are made to the owners of the mineral rights on leases, which include provincial governments (Crown) and freehold landowners, as well as to other third parties by way of contractual overriding royalties.
In Alberta, royalties on natural gas and NGLs are charged by the government based on an established monthly Reference Price. The Reference Price is meant to reflect the average price for natural gas and NGLs in Alberta. Gas cost allowance, custom processing credits and other incentive programs reduce the effective royalty rate.
Overriding royalties are generally paid to third parties where Daylight has entered into agreements to earn an interest in their mineral rights by investing capital in their property.
Oil royalty rates are generally a function of production rates on a per well basis and prices. They are also subject to certain reductions and incentives. Oil Crown royalties in Alberta are generally satisfied by delivering the required volume of oil to the Alberta provincial government.
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Royalties by type (000s) Q3 Q2 Q3 YTD YTD
2009 2009 2008 2009 2008
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Crown royalties $ 7,698 $ 8,521 $21,539 $27,286 $61,224
Freehold royalties 1,179 1,133 3,070 3,423 8,502
Overriding royalties 1,650 1,584 3,540 5,167 9,724
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Total $10,527 $11,238 $28,149 $35,876 $79,450
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$ per boe $ 4.87 $ 5.36 $ 14.05 $ 5.68 $ 13.96
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% of revenue 15.9 16.9 19.4 17.5 19.4
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Royalties by commodity (000s) Q3 Q2 Q3 YTD YTD
2009 2009 2008 2009 2008
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Natural gas $ (443) $ 3,153 $10,853 $ 9,993 $30,473
Oil and NGLs 10,970 8,085 17,296 25,883 48,977
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Total $10,527 $11,238 $28,149 $35,876 $79,450
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Natural gas ($/boe) $ (0.29) $ 2.16 $ 8.65 $ 2.29 $ 8.91
Oil and NGLs ($/boe) 17.55 12.66 23.07 13.33 21.55
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Total ($/boe) $ 4.87 $ 5.36 $ 14.05 $ 5.68 $ 13.96
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Natural gas (% of revenue) (1.6) 10.2 16.9 9.8 16.6
Oil and NGLs (% of revenue) 28.9 22.6 21.4 25.3 21.5
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Total (% of revenue) 15.9 16.9 19.4 17.5 19.4
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Overall royalty rates decreased to 15.9% of revenue in Q3 2009 from 16.9% of revenue in Q2 2009. Daylight received Gas Cost Allowance credits in Q3 2009 resulting in a recovery of $0.4 million or 1.6% of revenue. Had these credits not been received, Daylight's natural gas royalty rate for Q3 2009 would have been 16.6%. Oil and NGLs royalty rates increased to 28.9% of revenue during Q3 2009 as compared to 22.6% of revenue in Q2 2009 due to increased commodity prices. Total royalty rates decreased to 15.9% of revenue for Q3 2009 compared with 19.4% of revenue for Q3 2008. Year over year for the nine month period, total royalty rates decreased to 17.5% of revenue for YTD 2009 from 19.4% of revenue for YTD 2008, a change of 1.9% due to higher commodity prices realized during YTD 2008.
On October 25, 2007, the Alberta government introduced a proposed New Royalty Framework ("NRF") which took effect January 1, 2009. On April 10, 2008, the Alberta Government announced revisions to the NRF to increase royalty rates on conventional and non-conventional oil and natural gas production whereby royalty rates may increase to maximum rates of 50%, to introduce broader ranges of commodity prices in its sliding scale royalty calculations, and to eliminate royalty incentive and holiday programs with the exception of specific programs relating to deep oil and natural gas drilling, innovative technology and enhanced recovery programs. Subsequent to the legislation of the NRF in November 2008, the Transitional Royalty Plan ("TRP") was introduced in response to the economic downturn and declining commodity prices. The TRP offers reduced royalty rates for wells drilled on or later than November 19, 2008 which meet certain depth criteria. The TRP is in place for a maximum period of five years up to December 31, 2013.
On March 3, 2009, an incentive program (the "Energy Incentive Program") designed to encourage the execution of new drilling projects in Alberta was announced in response to the slowdown in drilling activity throughout the province of Alberta. The Energy Incentive Program provides for a drilling royalty credit for new conventional oil and natural gas wells that initiate drilling on or after April 1, 2009 and that complete drilling by March 31, 2010. The drilling credit is based on a $200 per meter credit on total meters drilled with a cap based on production levels and Alberta Crown royalties paid. The Energy Incentive Program also provides a reduced royalty rate of 5% on new wells for the first year of production up to an established total production volume. On June 25, 2009, the Alberta government extended the Energy Incentive Program by one year to March 31, 2011. The Trust adjusted portions of its capital program for Q1 2009 wells to take advantage of this program.
Approximately 95% of Daylight's reserves and production are in Alberta, with the balance located in British Columbia and Saskatchewan. Approximately 76% of current production is subject to Crown royalties, which are affected directly by the government royalty programs, and the remaining 24% of Daylight's 2009 royalties are related to freehold and override charges, which are not directly affected by these programs. Consequently, the NRF, TRP and the new Energy Incentive Program will impact Daylight's royalty rates, the effect of which is dependent upon commodity prices.
Future reserve and production addition activities are expected to be significantly impacted by changes to the royalty system. The Trust's depth of prospect inventory allows Daylight to select capital expenditure programs that provide the greatest value to our unitholders in the context of the expected change to the royalty system.
Financial Instruments
Financial instruments comprise accounts receivable, investments, accounts payable and accrued liabilities, derivative contracts, cash distributions payable, bank debt, and convertible debentures. Unless otherwise noted, carrying values reflect the current fair value of the Trust's financial instruments due to the short term to maturity. The Trust's investments held for trading include the trust units of Harvest Energy Trust ("Harvest") and shares of Midway Energy Ltd. ("Midway") (see "Investments" section below). The Trust also has an equity investment in Bengal Energy Ltd. ("Bengal") (see "Investments" section below). The investments held for trading have a fair value based on quoted market values of $2.1 million as at September 30, 2009. During Q3 2009, Daylight experienced a $1.1 million unrealized gain on these investments held for trading and a $0.1 million unrealized loss in Q2 2009. The investment in Bengal has a fair value based on quoted market value of $2.1 million as at September 30, 2009. At December 31, 2008, the investment in Bengal was written down to its market value. For the three and nine months ended September 30, 2009 th
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