CALGARY, March 11 /PRNewswire-FirstCall/ -- Highpine Oil & Gas Limited (TSX: HPX) ("Highpine" or the "Company") announces its record financial and operational results for the fourth quarter and year ended December 31, 2007.
2007 HIGHLIGHTS AND RESULTS - Production averaged 17,736 boe/d in 2007, up 51% from 11,779 boe/d in 2006. In the fourth quarter of 2007 average production of 19,716 boe/d represented a 44% increase over the 13,690 boe/d recorded in the same period in 2006. The 2007 production mix consisted of 64% liquids and 36% natural gas. Both the average annual and the fourth quarter volumes for 2007 represent production records for Highpine. - Liquids prices realized in 2007 increased 9.5% to $72.50/boe compared to $66.19/boe for the 2006 year. Average natural gas price realization for the year increased 4.7% to $7.39/mcf compared to $7.06/mcf for 2006. For 2008, no oil hedges are in place with 7,500 GJ/d of gas hedged to October 31, 2008, at an average $8.01/GJ through the summer months. - Production increases and improved price realizations contributed to strong revenue growth in 2007. Oil and natural gas revenues before hedging activities increased 63% for the 2007 year to $403.6 million from $247.8 million in 2006, fourth quarter revenues in 2007 improved 89% to $125.6 million from $66.6 million in 2006. For the 2007 year, cash from operations of $193.8 million ($2.83 per diluted share) represented a 52% increase from the $127.4 million ($2.17 per diluted share) recorded in 2006. In the fourth quarter of 2007 cash from operations increased 95% to $58.4 million ($0.85 per diluted share) from $30.0 million ($0.44 per diluted share) in the fourth quarter of 2006. - Operating costs in 2007 averaged $10.34/boe compared to $8.57/boe in 2006. Despite higher volumes, increases in processing costs, workover expenses, as well as costs associated with turnarounds at several facilities all contributed to the higher per unit operating costs of $10.34/boe. - Operating netbacks in 2007 were $33.28/boe compared to $33.05/boe in 2006. Fourth quarter operating netbacks were $34.98/boe compared to $27.62/boe for the same period in 2006. - Net capital expenditures for the year amounted to $199.5 million, with $61.9 million alone attributable to fourth quarter activity. Approximately 90% of the years expenditures were incurred in the Pembina area. - Highpine participated in drilling 34 gross wells (24.9 net) at a 84% success rate in 2007 with 8 gross wells (7.2 net) drilled in the fourth quarter at a 100% success rate. In 2007, Highpine received 23 new well license approvals in the Pembina Nisku area. This activity level constituted Highpine's most active year. - Capital expenditures in 2007 were focused on reserve development, facility expansions, land and seismic. Highpine's 2007 finding, development and acquisition costs (FD&A) per boe, including net changes in future development capital, were $30.04 proved and $30.23 proved plus probable. - Net general & administrative expenses (G&A) per boe of $1.88 for the year 2007 were reduced by 16% compared to 2006. In the fourth quarter, 2007 net G&A of $1.48 represented a decrease of 42% compared to the same period in 2006. Net G&A expenses for 2007 were $12.2 million compared to $9.7 million in 2006. - In 2007, a $358.1 million non-cash goodwill impairment charge in the year resulted in a net loss of $345.1 million, compared to net earnings of $7.0 million in 2006. - At year end, net debt of $174.8 million, expressed as a ratio to (trailing) cash flow, was 0.9:1 compared to 1.3:1 at December 31, 2006. 2007 OPERATIONS
Highpine's production increased from 17,375 boe/d in the first quarter of 2007 to a fourth quarter rate of 19,716 boe/d. A production base capable of producing in excess of 20,000 boe/d was established late in 2007 through successful drilling and facility improvements. Highpine's operated wells and facilities ran at an on-time efficiency rate of greater than 95% during the year. In 2007, the equipping and pipelining of 22 wells were completed in Pembina that added significant capability to Highpine's production base. This operating capability was tempered by delays in regulatory approvals and periods of unexpected down-time and curtailments imposed by third party midstream processing facilities, which ultimately affected sales volumes.
Highpine participated in the drilling of 34 wells in 2007 and achieved a drilling success rate of 84%. A total of 28 (21.8 net) wells were drilled in the Pembina Nisku Fairway as Highpine continued to be successful in obtaining sour well drilling licences. Drilling results of the Pembina program included 13 (11.4 net) oil and gas wells, 7 (4.8 net) shallow gas wells, 2 (1.7 net) service wells and 6 (3.9 net) dry holes with an overall drilling success rate in excess of 80%. The most significant was the drilling and completion of the 4,200 metre directional 16-36-48-8W5 well drilled into the Pembina Nisku WW pool. This well is currently producing at a restricted rate of 1,000 boe/d with GPP approval expected to be received in the second quarter. The balance of the wells in 2007 were drilled in the West Central Alberta Gas Fairway at a 100% success rate.
At year-end, Highpine's undeveloped land holdings totalled 309,000 net undeveloped acres of which approximately 56% or 174,000 net acres were in Pembina. Highpine also significantly increased its seismic data during 2007 to 2,069 square miles of 3D data and 3,672 miles of 2D data.
2007 YEAR-END RESERVES
Year end 2007 total proved reserves of 28.6 million barrels of oil equivalent (mmboe) and total proved plus probable reserves of 44.2 mmboe remained relatively flat compared to the year end 2006 reserves of 44.4 mmboe. Highpine's 2007 capital program replaced 120% of production on a total proved and probable basis, before revisions and the net effect of acquisitions and dispositions.
Poor production performance primarily at Ante Creek resulted in negative revisions to both total proved and proved plus probable gas and natural gas liquids reserves of 1.45 mmboe. Remaining reserves at Ante Creek now represent less than 1% of Highpine's total proved plus probable reserve base with little further downside risk. Positive revisions to total proved oil reserves of 1.40 mmbbls were largely due to the movement of probable additional reserves to the total proved category through successful drilling.
In 2007, $199.5 million of capital was incurred with $83.1 million spent on facilities, land and seismic, and the balance related to drilling and completions. Approximately $180 million was spent in the Pembina area, largely focused on the Nisku.
Total 2007 finding, development and acquisition costs ("FD&A"), excluding the net change in future development capital, for total proved reserves were $34.33/boe and for total proved plus probable reserves were $31.87/boe. Including the net change in future development capital, the FD&A cost for total proved reserves were $30.04/boe and for total proved plus probable reserves were $30.23/boe.
During 2007 a large number of the Nisku wells drilled were focused on infill and step-out locations, which generally target smaller reserves when compared to new pool discoveries. 2007 Nisku drilling resulted in reserves of approximately 500 mboe per well, which had an impact on the finding and development costs. Due to delays in well licensing along the NE extension of the Nisku trend, a number of Highpine's more attractive prospects from a new reserve potential, were not able to be drilled during 2007. A significant amount of Highpine's 2008 plans and capital program are focused on this high potential area where wells are currently drilling, being licensed and undergoing consultation.
Lower services costs currently being encountered in the industry and an internal focus on operational efficiency are expected to moderate the growing cost structure experienced by Highpine to date. These factors combined with drilling higher impact Nisku prospects in 2008 are expected to result in improved go forward F&D costs and recycle ratios.
Paddock, Lindstrom & Associates Ltd. ("Paddock") has evaluated the Company's reserves as at December 31, 2007. The reserves presented below, include Company working interests before royalty interests and before royalty costs. Where volumes are expressed on a barrel of oil equivalent (boe) basis, gas volumes have been converted to barrels of oil in the ratio of one barrel of oil to six thousand cubic feet of natural gas.
Summary of Crude Oil, NGL and Natural Gas Reserves and Net Present Values of Estimated Future Net Revenue as of December 31, 2007 Based on Forecast Price Assumptions(x) ------------------------------------------------------------------------- Natural Crude Oil NGL's Total December 31, 2007 Gas (6:1) (bcf) (mbbls) (mbbls) (mboe) ------------------------------------------------------------------------- Proved developed producing 48.81 10,394 3,877 22,405 Proved developed non-producing 8.94 1,411 639 3,540 Proved undeveloped 12.04 167 472 2,646 ------------------------------------------------------------------------- Total proved 69.79 11,972 4,988 28,592 Probable additional 42.78 6,094 2,371 15,594 ------------------------------------------------------------------------- Total proved plus probable 112.57 18,066 7,359 44,186 ------------------------------------------------------------------------- (x) Highpine working interest only - does not include Highpine royalty interests and royalty costs Net Present Values of Future Net Revenue ------------------------------------------------------- Before Income Taxes Discounted at (%/year) ------------------------------------------------------- Reserves Category 0 5 10 15 20 ---------- ---------- ---------- ---------- ----------- (Thousand of Dollars) Proved Developed Producing 816,117 707,311 630,623 572,789 527,231 Developed Non- Producing 118,344 100,031 87,162 77,547 70,052 ---------- ---------- ---------- ---------- ----------- Total Developed 934,461 807,342 717,785 650,336 597,283 Undeveloped 65,188 43,090 30,933 23,254 17,970 ---------- ---------- ---------- ---------- ----------- Total Proved 999,649 850,432 748,718 673,590 615,253 Probable 489,183 339,953 256,873 203,917 167,196 ---------- ---------- ---------- ---------- ----------- Total Proved Plus Probable 1,488,832 1,190,385 1,005,591 877,507 782,449 ---------- ---------- ---------- ---------- ----------- ---------- ---------- ---------- ---------- ----------- ------------------------------------------------------------------------- WTI @ CDN/US Oil & Gas Price Cushing Exchange AECO C Propane Butane Forecast $US/BBL Rate C$/MMBTU C$/BBL C$/BBL ------------------------------------------------------------------------- Year 2008 90.00 1.00 6.80 53.25 71.00 2009 88.00 1.00 7.28 52.04 69.38 2010 84.00 1.00 7.43 49.62 66.16 2011 82.00 1.00 7.58 48.40 64.54 2012 80.00 1.00 7.73 47.19 62.92 ------------------------------------------------------------------------- Prices escalated at 2% per year from 2012 Reserves Reconciliation(x) ------------------------------------------------------------------------- Natural Gas Crude Oil NGL's ------------------------------------------------------------------------- Total Proved & Total Proved & Total Proved & Proved Probable Proved Probable Proved Probable ------------------------------------------------------------------------- (bcf) (mbbls) (mbbls) Dec. 31, 2006 74.94 112.67 11,081 17,552 5,683 8,064 Discoveries and extensions 12.89 22.73 2,262 2,986 566 962 Acquisitions 1.77 2.19 - - 203 251 Dispositions 2.59 3.06 58 74 312 369 Revisions (3.19) (7.93) 1,403 318 268 (129) Production (14.03) (14.03) (2,716) (2,716) (1,420) (1,420) ------------------------------------------------------------------------- Dec. 31, 2007 69.79 112.57 11,972 18,066 4,988 7,359 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ---------------------------------- Combined BOE ---------------------------------- Total Proved & Proved Probable ---------------------------------- (mboe) Dec. 31, 2006 29,254 44,395 Discoveries and extensions 4,976 7,736 Acquisitions 498 616 Dispositions 801 953 Revisions 1,139 (1,134) Production (6,474) (6,474) ---------------------------------- Dec. 31, 2007 28,592 44,186 ---------------------------------- ---------------------------------- (x) Highpine working interests only - does not include Highpine royalty interests and royalty costs NEW ROYALTY FRAMEWORK (NRF)
On October 25, 2007, the Government of Alberta announced a proposed NRF for oil and natural gas royalties in the Province of Alberta effective January 1, 2009. Highpine requested that Paddock estimate the impact to the reserve evaluation based on currently released information on the proposed NRF. To date the Government of Alberta has not provided enough clarity on a number of issues that would permit Paddock to provide a precise calculation of net reserves and net present values under the proposed NRF. In addition, it is possible that the announced changes may be amended before coming into effect. Under the forecast price assumptions, Paddock has estimated that the NRF change to the before tax net present value, discounted at 10%, of the net estimated future revenue from proved plus probable reserves would be a reduction of approximately 20% as at December 31, 2007. The NRF will impact future drilling decisions in order for the Company to maintain acceptable rates of return on its capital deployed.
2008 OUTLOOK 2008 Guidance 2007 Actuals ----------------------------------- Average production (boe/d) 20,500-21,000 17,736 Capital expenditures $150 million $199.5 million Operating costs (/boe) $10.50-$10.75 $10.34 G&A (/boe) $1.60-$1.80 $1.88
Highpine's production growth is expected to continue into 2008, bringing on production proven through 2007 drilling as well as new 2008 projects.
A significant portion of Highpine's production comes from the Pembina Nisku Fairway which is highly dependent upon four major gas processing facilities in the vicinity. A strong focus of the Company in 2008 is to work closely with its service providers, and partners in the area, to improve on-time performance, reliability and flexibility within the complicated Pembina network. Downtime associated with a lack of acid gas injection capacity at a Brazeau area facility in January and February will result in first quarter 2008 production averaging approximately 18,000 boe/d. This specific issue was mitigated in February, in part due to the disposition of a Highpine wellbore for acid injection to the facility operator.
During the first week of March 2008, production has ramped up to an estimated 20,000 boe/d with the Violet Grove facility at full volume, the upgraded Brazeau 6-29 compressor station back on line and continued optimization of the Paddy Creek sales line. In addition, several Pembina Nisku wells are expected to be tied-in and brought on stream prior to the end of March. Other projects, initiated by Keyera at their Brazeau facility, are aimed at allowing acid gas to be off-loaded to other facilities in their system with the objective of minimizing curtailments at Brazeau in the future with respect to acid gas issues. All of these projects, focused in the first quarter of 2008, are expected to contribute to supporting production volumes for the remaining quarters of 2008 in excess of 20,000 boe/d per quarter.
In 2008 to date, Highpine has participated in drilling 11 (4.8 net) wells resulting in 1 (1.0 net) potential Nisku oil/gas well, 9 (3.6 net) potential gas wells and 1 (0.2) dry hole at a 98% success rate. Highpine currently has three drilling operations in progress, two in Pembina targeting the Nisku and one in Joffre.
A significant portion of the 2008 capital expenditures (up to $70 million), is focused on exploration and development activities in the northeast portion of the Pembina Nisku Fairway: Tomahawk, Highvale and Rocky Rapids. This capital allocation accounts for up to 21 (19 net) wells and substantial pipelining and associated infrastructure. This area is northeast of the established productive Nisku trend of which Highpine has extensive land holdings and seismic coverage. Two notable discoveries have been made in this area in the past year, substantially reducing risk and increasing the prospectivity for finding oil in the area. Public consultation has been ongoing and continues in the area as several well licenses have been applied for with many others in the process of application. Two well licenses in the Rocky Rapids area, from the Alberta Energy Resources Conservation Board (ERCB), have been received with the first Nisku well drilled by Highpine in this area to be initiated prior to spring break-up. Due to the long lead-times required for licensing, building new infrastructure, bring on production in this area, and other regulatory matters, no meaningful production volumes are expected to be contributed from this area in 2008.
Approximately $50 million of the 2008 capital expenditures is earmarked for other exploration and development activity in the Pembina Nisku Fairway including development of the WW South pool and new exploration.
It is expected that cash flow generated in 2008 will exceed capital expenditures given the stronger than expected commodity price environment we are experiencing early in 2008. Highpine has recently entered into three natural gas swaps for summer gas, covering the period April 2008 - October 2008, for 7,500 GJ/d at an average of Cdn $8.01/GJ. Representing approximately 20% of Highpine's daily gas production, this support along with generally higher natural gas pricing, has prompted Highpine to internally review gas projects planned for later in the year as well as those currently not budgeted. Natural gas hedges of 2,500 GJ/d at an average swap price of Cdn $7.69/GJ remain through to the end of March 2008, as does a natural gas collar, of no consequence, for 5,000 GJ/d at Cdn $6.00 - Cdn $11.10. Highpine currently has no oil hedges in place. Baring any changes to Highpine's planned capital expenditures, any cash in excess of capital requirements will be applied against bank debt. The impact of proposed royalty changes in Alberta, technical results from activity undertaken early in 2008, commodity prices, regulatory requirements, or any other unforeseen event, may impact the capital expenditures for any of the activity areas described above.
Jonathan Lexier, President and CEO explains:
"2008 represents both an exciting and interesting year for Highpine. We have reduced our capital exposure and at the same time are focusing a disproportionate share of that capital program on a lightly explored and undeveloped area with little expectation of meaningful production in this calendar year. This area represents the next phase our growth in the Nisku fairway and we are very excited about the prospects that lay ahead and the potential for volume growth in 2009 and beyond. In 2008, despite the much reduced capital spent in our traditional focus areas (Violet Grove, Brazeau and Easyford), we are still anticipating the potential for approximately 15% growth or greater on our existing production base. Our focus in 2008 will be on improving our capital efficiency and operating reliability while still delivering a growth profile with an eye to 2009 and beyond."
CONFERENCE CALL ------------------------------------------------------------------------- Highpine will host a conference call for analysts, investors and interested parties, to discuss its financial and operational results at 8:30 am MDT, on Wednesday, March 12, 2008. Jonathan Lexier, President and Chief Executive Officer, as well as members of Highpine's executive team, will be in attendance. The call can be accessed toll free by dialing Canada and USA: 1-800-319-4610; Outside Canada and USA: 1-604-638-5340. Please phone in 10-15 minutes prior to the start of the call. The conference call will also be broadcast live over the internet on Highpine's website located at http://www.highpineog.com/. Digital Playback will be available until April 11, 2008 in North America Toll Free: 1-800-319-6413, Pin Code: 6639 followed by the # sign. ------------------------------------------------------------------------- CORRECTION
As stated in the March 10, 2008 press release, Jonathan Lexier will be presenting at the FirstEnergy/Societe Generale East Coast Canadian Energy Conference taking place March 12 to 14, 2008 in New York City, New York at the Waldorf Astoria. Please be advised that Jonathan will be presenting @ 9:47 am (EDT) on Friday, March 14, 2008 (instead of 10:04 am EDT). To listen and view this online event, please visit http://remotecontrol.jetstreammedia.com/14711. The presentation will be available in an archived version at this link for 30 days following the live presentation. For more information on the webcast, please visit http://www.firstenergy.com/.
------------------------------------------------------------------------- Three months ended Twelve months ended ($000s, except December 31, December 31, per share and % % share numbers) 2007 2006 Change 2007 2006 Change ------------------------------------------------------------------------- Financial Total revenue(1) 122,178 67,552 81 401,297 254,938 57 Cash from operations(2) 58,357 29,973 95 193,840 127,440 52 Per share - diluted 0.85 0.44 93 2.83 2.17 30 Net earnings (loss)(3) 19,805 (5,446) - (345,054) 6,953 - Per share - diluted 0.29 (0.08) - (5.09) 0.12 - Net debt(4) 174,821 169,570 3 174,821 169,570 3 Total assets 1,062,576 1,392,911 (24) 1,062,576 1,392,911 (24) Capital expenditures(5) 61,948 72,711 (15) 199,513 222,214 (10) Total shares outstanding (#) 67,886 67,648 - 67,886 67,648 - Weighted average shares Outstanding - diluted (#) 68,408 68,522 - 68,456 58,674 17 ------------------------------------------------------------------------- Operating Average daily production Crude oil and NGLs (bbls/d) 13,394 8,653 55 11,332 7,554 50 Natural gas (mcf/d) 37,930 30,221 26 38,426 25,350 52 ------------------------------------------------------------------------- Total (boe/d) 19,716 13,690 44 17,736 11,779 51 ------------------------------------------------------------------------- Average selling prices(6) Crude oil and NGLs ($/bbl) 82.38 58.37 41 72.50 66.19 10 Natural gas ($/mcf) 6.89 7.24 (5) 7.39 7.06 5 ------------------------------------------------------------------------- Total ($/boe) 69.22 52.88 31 62.34 57.64 8 ------------------------------------------------------------------------- Wells drilled - gross (net) (#) Oil 4(3.9) 8(6.2) - 10(8.1) 15(11.5) - Natural Gas 4(3.3) 8(4.6) - 16(11.2) 43(25.0) - Abandoned/other -(-) 3(2.5) - 8(5.6) 16(10.2) - ------------------------------------------------------------------------- Total 8(7.2) 19(3.3) - 34(24.9) 74(46.7) - Drilling success rate (%) 100 95 - 84 85 - ------------------------------------------------------------------------- Operating netback ($/boe) Oil and natural gas sales 69.22 52.88 31 62.34 57.64 8 Royalties (20.13) (14.80) 36 (18.04) (16.40) 10 Operating costs (11.96) (10.42) 15 (10.34) (8.57) 21 Transportation costs (0.23) (0.62) (63) (0.76) (0.71) 7 Realized hedging gain (loss) (1.92) 0.58 - 0.08 1.09 (93) ------------------------------------------------------------------------- Operating netback 34.98 27.62 27 33.28 33.05 1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Total revenue includes realized and unrealized hedging losses and gains. (2) Cash from operations is calculated as cash flow from operating activities before the change in non-cash working capital and abandonment expenditures. (3) Net loss for the 2007 periods includes a non-cash goodwill impairment charge of $358.1 million (4) Net debt includes working capital excluding unrealized financial instruments. (5) Capital expenditures include property acquisitions and are presented net of proceeds of disposals. (6) The average selling prices reported are before hedging activities. MANAGEMENT'S DISCUSSION AND ANALYSIS
This Management's Discussion and Analysis (MD&A) is dated and based on information at March 11, 2008. This MD&A has been prepared by management and should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2007 and audited consolidated financial statements and MD&A for the year ended December 31, 2006 for a complete understanding of the financial position and results of operations of Highpine Oil & Gas Limited ("Highpine" or the "Company"). The audited consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada. All references to dollar values refer to Canadian dollars unless otherwise stated.
This MD&A uses the terms "funds flow from operations," "funds flow" and "funds flow per share," which are not recognized measures under Canadian GAAP. Management believes that in addition to cash flow from operating activities, funds flow is a useful supplemental measure as it demonstrates Highpine's ability to generate cash necessary to repay debt or fund future growth through capital investment before changes in non-cash working capital balances. Investors are cautioned, however, that this measure should not be construed as an alternative to cash flow from operating activities determined in accordance with GAAP as an indication of Highpine's performance. Highpine's method of calculating funds flow may differ from other companies, especially those in other industries and accordingly may not be comparable to measures used by other companies. Highpine calculates funds from operations as cash from operating activities before the change in non-cash working capital related to operating activities and abandonment expenditures.
The following table reconciles the cash flow from operating activities to funds from operations:
------------------------------------------------------------------------- Three Twelve months ended months ended December 31, December 31, 2007 2006 2007 2006 ------------------------------------------------------------------------- ($000s) Cash flow from operating activities 55,912 39,109 186,569 109,054 Change in non-cash operating working capital 1,989 (9,452) 5,799 18,018 Abandonment expenditures 456 316 1,472 368 ------------------------------------------------------------------------- Funds from operations 58,357 29,973 193,840 127,440 -------------------------------------------------------------------------
Highpine also uses operating netback as an indicator of operating performance. Operating netback is calculated on a per BOE basis taking the sales price and deducting royalties, operating costs, transportation costs and realized hedging gains and losses.
Where amounts are expressed on a barrel of oil equivalent (BOE) basis, natural gas volumes have been converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet equal to one barrel of oil equivalent unless otherwise indicated. This conversion ratio of 6:1 is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. BOE figures may be misleading, particularly if used in isolation.
Additional information relating to Highpine Oil & Gas Limited, including the Company's annual information form, is available on SEDAR at http://www.sedar.com/ and on the Company's website at http://www.highpineog.com/.
Financial Results Oil and Natural Gas Revenue ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- ($000s) Crude oil and natural gas liquids (NGLs) revenue 101,520 46,469 118 299,896 182,509 64 Natural gas revenue 24,033 20,132 19 103,702 65,295 59 ------------------------------------------------------------------------- 125,553 66,601 89 403,598 247,804 63 Realized hedging gain (loss) (3,474) 727 - 487 4,703 (90) Unrealized hedging gain (loss) 99 224 (56) (2,788) 2,431 - ------------------------------------------------------------------------- Total oil and natural gas revenue 122,178 67,552 81 401,297 254,938 57 ------------------------------------------------------------------------- -------------------------------------------------------------------------
For the twelve months ended December 31, 2007 total oil and natural gas revenue increased to $401.3 million from $254.9 million for the twelve months ended December 31, 2006 due to production volume increases combined with higher commodity prices received in 2007. Total oil and natural gas revenue was negatively impacted by $2.8 million of unrealized hedging losses compared to $2.4 million of unrealized hedging gains in the comparative twelve month period.
Production ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Daily Production Crude oil and NGLs (Bbls/d) 13,394 8,653 55 11,332 7,554 50 Natural gas (Mcf/d) 37,930 30,221 26 38,426 25,350 52 ------------------------------------------------------------------------- BOE/d 19,716 13,690 44 17,736 11,779 51 ------------------------------------------------------------------------- Production Mix ------------------------------------------------------------------------- Crude oil and NGLs 68% 63% 8 64% 64% - Natural gas 32% 37% (14) 36% 36% - ------------------------------------------------------------------------- 100% 100% - 100% 100% - ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- (BOE/d) Daily Production by Area Pembina Nisku Fairway 15,800 9,700 63 13,817 8,293 67 West Central Alberta Gas Fairway 3,203 3,399 (6) 3,191 2,858 12 Bantry/Retlaw 573 492 16 598 475 26 Other 140 99 41 130 153 (15) ------------------------------------------------------------------------- Total 19,716 13,690 44 17,736 11,779 51 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Prior periods have been reclassified to conform with current period presentation.
Production for the twelve months ended December 31, 2007 increased 51 percent to 17,736 BOE/d from 11,779 BOE/d for the twelve months ended December 31, 2006. The increase is attributable to a full year of production from the acquisition of Kick Energy Corporation ("Kick") on August 1, 2006 and new production from the Company's drilling program. The majority of the increases were from the Pembina Nisku fairway where 28 (21.8 net) wells were drilled out of the Company's total for 2007 of 34 (24.9 net) wells.
Highpine's original guidance for 2007 was production targeted in excess of 20,000 BOE/d. The 11 percent shortfall is primarily attributable to unexpected downtime and curtailments at certain non-operated midstream processing facilities as a result of unscheduled turnarounds and maintenance. Highpine is taking proactive steps to improve all of its recipient sour gas plant operations for 2008 as well as other facilities optimization initiatives including installing an additional booster compressor on one of its major production pipelines leaving the Violet Grove oil battery.
Pricing ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Selling Prices Before Hedges Crude oil and NGLs ($/Bbl) 82.38 58.37 41 72.50 66.19 10 Natural gas ($/Mcf) 6.89 7.24 (5) 7.39 7.06 5 ------------------------------------------------------------------------- Total combined ($/BOE) 69.22 52.88 31 62.34 57.64 8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Benchmark Prices WTI oil (US$/Bbl) 90.77 60.22 51 72.27 66.25 9 US$/Cdn$ exchange rate 1.02 0.87 17 0.94 0.88 7 AECO natural gas ($/Mcf) (monthly) 6.02 6.91 (13) 6.65 6.51 2 ------------------------------------------------------------------------- -------------------------------------------------------------------------
The WTI benchmark price for crude oil was 9 percent higher for 2007 compared to 2006 resulting in higher realized prices. Highpine's realized natural gas price increased for 2007 in response to a 2 percent increase in the AECO benchmark price.
Commodity Price Risk Management
Highpine's ability to execute its business strategy is dependent on generating cash flow that can be reinvested into its capital program. The Company utilizes financial and physical commodity price hedges to protect cash flow against commodity price volatility. Highpine may enter into commodity price hedges to a maximum of 50 percent of production. Entering into commodity price hedges may limit Highpine's ability to participate in commodity price increases to the extent of the hedged production.
------------------------------------------------------------------------- Twelve months ended December 31, 2007 2006 Crude Oil Natural & NGLs Gas Total Total (Bbl) (Mcf) (BOE) (BOE) ------------------------------------------------------------------------- Average volumes hedged (per day) 5,500 13,542 7,757 4,736 Percent of production hedged 49% 35% 44% 40% Realized hedging gain (loss) ($) (0.91) 0.30 0.08 1.09 ------------------------------------------------------------------------- -------------------------------------------------------------------------
For the twelve months ended December 31, 2007, Highpine realized a $4.2 million natural gas hedging gain which was largely offset by a $3.7 million crude oil hedging loss. For the twelve months ended December 31, 2006, Highpine realized a $5.3 million natural gas hedging gain and a $0.6 million crude oil hedging loss.
------------------------------------------------------------------------- Twelve months ended December 31, 2007 2006 Crude Oil Natural & NGLs Gas Total Total ------------------------------------------------------------------------- ($000s) Realized hedging gain (loss) (3,748) 4,235 487 4,703 Unrealized hedging gain (loss) (1,103) (1,685) (2,788) 2,431 ------------------------------------------------------------------------- Total hedging gain (loss) (4,851) 2,550 (2,301) 7,134 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The following contracts were outstanding at December 31, 2007: ------------------------------------------------------------------------- Term Contract Volume Fixed Price ------------------------------------------------------------------------- Feb 07 to Mar 08 Natural Gas Swap 1,250 GJs/d Cdn $7.68/GJ Feb 07 to Mar 08 Natural Gas Swap 1,250 GJs/d Cdn $7.70/GJ Jul 06 to Mar 08 Natural Gas Collar 5,000 GJs/d Cdn $6.00 to $11.10/GJ ------------------------------------------------------------------------- -------------------------------------------------------------------------
As at December 31, 2007, the unrealized mark-to-market gain on outstanding natural gas contracts was $0.4 million. The unrealized mark-to-market gain reflects the market price Highpine would receive if the counterparty were to buy out the outstanding contracts. The determination of the fair value of outstanding contracts at December 31, 2007 requires assumptions to be made of the underlying future commodity prices.
Subsequent to December 31, 2007, Highpine entered into the following contracts: ------------------------------------------------------------------------- Term Contract Volume Fixed Price ------------------------------------------------------------------------- Apr 08 to Oct 08 Natural Gas Swap 2,500 GJs/d Cdn $8.01/GJ Apr 08 to Oct 08 Natural Gas Swap 2,500 GJs/d Cdn $7.94/GJ Apr 08 to Oct 08 Natural Gas Swap 2,500 GJs/d Cdn $8.10/GJ ------------------------------------------------------------------------- Royalty Expense ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Total royalties, net of ARTC 36,515 18,635 96 116,784 70,529 66 ($000s) As a percent of oil and natural gas sales (before hedging) 29% 28% 4 29% 28% 4 $/BOE 20.13 14.80 36 18.04 16.40 10 ------------------------------------------------------------------------- -------------------------------------------------------------------------
Royalty rates as a percentage of oil and natural gas sales during the twelve months of 2007 were comparable to the twelve months of 2006.
On October 25, 2007, the Alberta government introduced a framework to increase royalty rates entitled the New Royalty Framework ("NRF"). The NRF is proposed to be effective January 1, 2009. Under the NRF, Crown royalties payable for crude oil will be set by a single sliding rate formula containing separate elements that account for oil price and well production. Maximum royalty rates for crude oil are to increase from 35 percent to 50 percent. Crown royalties payable for natural gas will be set by a formula sensitive to price and production volume. Natural gas royalty rates, currently 5 percent to 35 percent, are to range from 5 percent to 50 percent. If enacted as proposed, the NRF will increase Highpine's royalty expense commencing in 2009.
During the 2006 year the Company received $500,000 of Alberta Royalty Tax credits (ARTC) which was discontinued for 2007.
Operating Costs ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Operating costs ($000s) 21,690 13,124 65 66,937 36,839 82 $/BOE 11.96 10.42 15 10.34 8.57 21 ------------------------------------------------------------------------- -------------------------------------------------------------------------
For the twelve months ended December 31, 2007, operating costs on a per BOE basis increased 21 percent compared to the twelve months ended December 31, 2006. The increases were a result of several factors including higher gas processing costs as a result of increased gas production volumes in the Pembina area, higher power costs due to the increasing utilization of electric submersible pumps and increases in repair and maintenance and contract operating costs. In addition, the Company incurred increased workover costs largely related to electric submersible pumps as well as the turnaround costs on the Violet Grove oil battery.
Transportation Costs ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Transportation costs ($000s) 426 778 (45) 4,925 3,069 60 $/BOE 0.23 0.62 (63) 0.76 0.71 7 -------------------------------------------------------------------------
For the twelve months ended December 31, 2007, transportation costs on a per BOE basis increased 7 percent compared to the comparative 2006 period primarily as a result of higher sulphur transportation charges. Increased sour oil production resulted in larger quantities of sulphur which was transported by truck and rail to Vancouver, British Columbia and other disposal locations. Railway interruptions during 2007 further increased the cost of shipping sulphur volumes.
Operating Netback ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- ($/BOE) Sales price before hedging 69.22 52.88 31 62.34 57.64 8 Royalties (20.13) (14.80) 36 (18.04) (16.40) 10 Operating costs (11.96) (10.42) 15 (10.34) (8.57) 21 Transportation costs (0.23) (0.62) (63) (0.76) (0.71) 7 ------------------------------------------------------------------------- Netback before hedges 36.90 27.04 36 33.20 31.96 4 Realized hedging gain (loss) (1.92) 0.58 - 0.08 1.09 (93) ------------------------------------------------------------------------- Operating netback 34.98 27.62 27 33.28 33.05 1 ------------------------------------------------------------------------- -------------------------------------------------------------------------
Operating netback before realized hedging gains was $33.20/BOE for the twelve months ended December 31, 2007 compared to $31.96/BOE for the twelve months ended December 31, 2006. Increases in commodity prices were largely offset by higher royalties and operating costs.
General and Administrative Expenses ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Gross expenses ($000s) 3,586 4,436 (19) 15,484 12,931 20 Capitalized ($000s) (903) (1,227) (26) (3,313) (3,249) 2 ------------------------------------------------------------------------- Net expenses ($000s) 2,683 3,209 (16) 12,171 9,682 26 ------------------------------------------------------------------------- ------------------------------------------------------------------------- $/BOE 1.48 2.55 (42) 1.88 2.25 (16) percent capitalized 25% 28% (11) 21% 25% (16) ------------------------------------------------------------------------- -------------------------------------------------------------------------
Gross expenses increased 20 percent to $15.5 million for the twelve months ended December 31, 2007 from $12.9 million in 2006 primarily as a result of higher personnel costs. Average employee and consultant count increased commensurate with the growth of the Company. At December 31, 2007, Highpine had 60 Calgary based office employees compared to 55 at December 31, 2006. In addition, Highpine incurred higher severance costs and recruiting costs and implemented a defined contribution retirement plan for employees. On a per BOE basis, general and administrative expenses decreased 16 percent to $1.88/BOE from $2.25/BOE in 2006 as a result of higher production.
Stock-Based Compensation
Stock-based compensation expense totaled $4.5 million in 2007 compared to $5.7 million in 2006. The decrease is attributable to options that were cancelled in 2007 which resulted in a recovery of previously recognized stock-based compensation expense.
On March 21, 2007, 1.9 million stock options which had been granted to non-officer employees at exercise prices ranging from $14.92 to $23.25 were repriced to an exercise price of $12.05. The vesting period of all repriced options was reset such that the repriced options vest as to one-quarter thereof on each of the first, second, third and fourth anniversaries of the repricing. An additional $5.1 million of stock based compensation expense will be recorded over the four year vesting period of the repriced options as a result of the reprice.
Interest and Finance Costs
Interest and finance costs for 2007 were $9.4 million versus $5.0 million in 2006. This increase was primarily due to higher average debt levels.
Depletion, Depreciation and Accretion ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Depletion and depreciation ($000s) 56,341 36,682 54 193,302 124,627 55 Accretion of asset retirement obligation ($000s) 228 220 4 905 679 33 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total DD&A 56,569 36,902 53 194,207 125,306 55 ------------------------------------------------------------------------- ------------------------------------------------------------------------- DD&A rate $/BOE 31.19 29.31 6 30.00 29.15 3 ------------------------------------------------------------------------- -------------------------------------------------------------------------
The depletion, depreciation, and accretion (DD&A) rate of $30.00 per BOE for the twelve months ended December 31, 2007 was comparable to the $29.15 per BOE for the twelve months ended December 31, 2006.
Income Taxes
The Company received a refund of $46,000 in 2007 in respect of Large Corporation tax which was over-paid in a prior year. The Company also paid cash taxes of $1.4 million in 2007 as a result of the reassessment of the 2004 and 2005 tax years of Kick. The reassessment did not impact Highpine's current tax expense, net earnings or funds flow as the tax liability had been recorded in 2006 in the Kick purchase equation.
The Company recorded a reduction in future taxes of $20.9 million in 2007. The reduction is primarily attributable to a $22.8 million reduction in Highpine's future income tax liability as a result of a substantively enacted reduction in Canadian federal income tax rates. Canadian federal income tax rates will decrease from 22.1 percent in 2007 to 15 percent in 2012. In 2006, Highpine realized a future tax reduction of $8.0 million primarily due to a decrease in Canadian federal and Alberta tax rates which resulted in a $9.1 million tax reduction.
Although current tax horizons depend on product prices, production levels, royalty rates and the nature, magnitude and timing of capital expenditures, the Company currently believes no cash income tax will be payable in 2008 or 2009.
Goodwill
Highpine recorded goodwill on the acquisitions of Kick, White Fire Energy Ltd., Vaquero Energy Ltd. and Rubicon Energy Corp. Goodwill represents the excess of the purchase price of the acquired businesses over the fair value of net assets acquired. Goodwill is assessed for impairment annually and between annual tests when events or circumstances indicate that goodwill might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount is compared to its fair value. When the carrying amount exceeds its fair value, goodwill is considered to be impaired and the second step of the impairment test is performed. The implied fair value of goodwill is determined in the same manner as the value of the goodwill is determined in a business combination using the fair value of the Company as if it were the purchase price. When the carrying amount of the Company's goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess.
At September 30, 2007, the Company identified indicators of impairment including a decline in the Company's share price. Goodwill was tested for impairment and it was determined that goodwill was impaired. An impairment of goodwill of $358.1 million was recorded to earnings representing all of the previously recorded goodwill. The write-down is not an indication of the underlying value of the Company's properties.
Funds from Operations and Net Earnings (Loss) ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 % Change 2007 2006 % Change ------------------------------------------------------------------------- Funds from operations ($000s) 58,357 29,973 95 193,840 127,440 52 Per diluted share ($) 0.85 0.44 93 2.83 2.17 30 Net earnings (loss) ($000s) 19,805 (5,446) - (345,054) 6,953 - Per diluted share ($) 0.29 (0.08) - (5.09) 0.12 - -------------------------------------------------------------------------
For the twelve months ended December 31, 2007, funds from operations increased 52 percent to $193.8 million from $127.4 million for the twelve months ended December 31, 2006 due to production increases and crude oil price increases. Funds from operations per diluted share increased 30 percent to $2.83.
During the twelve months of 2007, Highpine incurred a net loss of $345.1 million, compared to net earnings of $7.0 million for the twelve months ended December 31, 2006. The magnitude of the net loss is attributable to a $358.1 million impairment of goodwill incurred during the three months ended September 30, 2007. Net earnings for the twelve months ended December 31, 2007 included a $22.8 million (2006 - $9.1 million) non-recurring future tax reduction realized as a result of enacted Canadian federal and Alberta tax rate reductions.
The NRF is proposed to be effective January 1, 2009 and as such funds from operations and net earnings for the year ended December 31, 2007 and the year ending December 31, 2008 will be unaffected. However, funds from operations and net earnings for the year ending December 31, 2009 and subsequent years will be negatively impacted by the expected higher overall royalty rates. The actual effect of the NRF on Highpine will be determined based on the actual legislation enacted, the production rates, commodity prices and product mix after January 1, 2009. If the changes were enacted and applicable today and based on the Company's interpretation of publicly available information, Highpine estimates that the potential effect on funds from operations from current production would result in an approximate reduction of 29 percent based on a benchmark price of WTI US$70/Bbl and AECO Cdn$6.00/MMbtu and using a par foreign exchange ratio.
Long-Term Investment
The Company's long-term investment of $1.2 million is comprised of 1,080,000 common shares of In-Depth Resources Ltd., a privately held oil and natural gas company. At December 31, 2007, Highpine assessed the carrying amount of its investment for impairment which resulted in the Company recording an impairment provision of $300,000 against the carrying amount which was charged to earnings.
Liquidity and Capital Resources
At December 31, 2007, the Company had a revolving term credit facility of $230 million and a demand operating credit facility of $20 million with $147 million drawn against these facilities, thereby providing remaining credit capacity of $103 million. At December 31, 2007, the Company had a working capital deficiency of $28.1 million and net debt of $174.8 million. The Company's working capital deficiency is expected to fluctuate based on the timing of the Company's capital expenditure program which is typically most active during the first and fourth quarters. The Company's working capital deficiency is funded from funds available from existing credit facilities and funds flow from operations.
------------------------------------------------------------------------- As at December 31, December 31, 2007 2006 ------------------------------------------------------------------------- ($000s) Capitalization Bank debt 146,675 138,890 Working capital deficiency(1) 28,146 30,680 ------------------------------------------------------------------------- Net debt 174,821 169,570 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Shares outstanding (#) 67,886 67,648 Market price at end of period ($) 9.98 15.70 Market capitalization 677,502 1,062,074 ------------------------------------------------------------------------- Total capitalization 852,323 1,231,644 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net debt as a percent of total capitalization 21% 14% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Funds from operations 193,840 127,440 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net debt to trailing funds from operations ratio 0.90 1.33 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Working capital excludes unrealized financial instruments. At March 11, 2008, the Company's bank debt was approximately $138 million.
In light of the uncertainty surrounding the New Royalty Framework, the Board of Directors has approved a capital budget for 2008 of $150 million, being an amount which is below anticipated 2008 funds flow. The Company's lenders review the credit facilities semi-annually and as a result of the New Royalty Framework it is expected that the maximum funds available under the facilities may be reduced. The capital budget will enable Highpine to reduce its debt in anticipation of a reduction in the maximum funds available under the Company's credit facilities. If clarification of the NRF can be obtained which removes the uncertainty surrounding deep oil drilling in Alberta, the capital budget may be expanded.
Commitments and Contractual Obligations
The Company enters into contractual obligations in the normal course of operations including purchase of assets and services, joint operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations and employment agreements. These obligations are of a recurring and consistent nature and impact funds flow in an ongoing manner. The Company was committed to make less routine future payments pursuant to contractual obligations at December 31, 2007 as follows:
------------------------------------------------------------------------- ($ thousands) Total 2008 2009/2010 2011/2012 After 2013 ------------------------------------------------------------------------- Operating leases(1) 6,370 1,484 2,566 2,320 - Long-term debt(2) 146,675 - 146,675 - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- 1) Operating leases include leases for office space and field equipment. 2) In the event that the credit facilities are not extended, the amount outstanding would be repayable on May 26, 2009. Management fully anticipates that the credit facilities will be extended. Capital Expenditures
Capital expenditures, excluding corporate acquisitions, property acquisitions, and property dispositions totaled $202.7 million for the twelve months ended December 31, 2007 compared to $194.8 million for the twelve months ended December 31, 2006. The Company's capital program is heavily weighted to the Pembina Nisku fairway which accounted for 87 percent of capital expenditures for the twelve months ended December 31, 2007. During the twelve months ended December 31, 2007, Highpine drilled 34 (24.9 net) wells which resulted in 10 (8.1 net) oil wells, 16 (11.2 net) gas wells, 2 (1.7 net) water source wells and 6 (3.9 net) dry holes. During the third quarter of 2007, the Company disposed of undeveloped properties in a non-core area for proceeds of $3.6 million.
In 2008, the Company plans to participate in 34 (28 net) wells. ------------------------------------------------------------------------- Twelve months ended December 31, 2007 2006 % Change ------------------------------------------------------------------------- ($000s) Land 11,292 17,392 (35) Geologic and geophysical 7,663 10,431 (27) Drilling and completions 119,453 110,665 8 Facilities and equipment 60,943 52,649 16 Capitalized general and administrative 3,313 3,258 2 Office and other 70 358 (80) ------------------------------------------------------------------------- Total capital expenditures 202,734 194,753 4 ------------------------------------------------------------------------- Property acquisitions 495 27,461 (98) ------------------------------------------------------------------------- Property dispositions (3,716) - 100 ------------------------------------------------------------------------- Corporate acquisitions(1) - 440,895 (100) ------------------------------------------------------------------------- Total capital expenditures and acquisitions 199,513 663,109 (70) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Represents total consideration for the transactions, including fees, but is prior to the related future income tax liability and asset retirement obligation. Outstanding Common Shares
As at March 11, 2008, the Company had 67.9 million class A common shares outstanding and had granted options to directors, officers, employees and consultants to acquire a further 5.0 million class A common shares with an average exercise price of $10.40 per share.
FOURTH QUARTER REVIEW
Highpine increased its average production to 19,716 BOE/d in the fourth quarter of 2007 compared to 13,690 BOE/d in the fourth quarter of 2006. The increase in production is attributable to the Company's drilling programs. Production in the fourth quarter of 2007 was curtailed due to operational issues at certain recipient gas plants. Highpine is taking steps to improve all of its recipient gas plant operations for 2008 including installing an additional booster compressor on one of its major sales lines from the Violet Grove oil battery to increase throughput capacity of sour natural gas.
Operating netback before hedging activities increased 36 percent to $36.90/BOE in the fourth quarter of 2007 compared to $27.04/BOE in the fourth quarter of 2006. The increase is primarily attributable to stronger benchmark crude oil prices which increased 51 percent to US$90.77/Bbl in the fourth quarter of 2007 compared to the fourth quarter of 2006. The increase in crude oil prices was partially offset by a 17 percent increase in the value of the Canadian dollar relative to the US dollar. Highpine's operating costs on a per BOE basis were 15 percent higher than the comparable 2006 period as a result of higher processing costs and higher workover costs. Highpine's transportation costs were 63 percent lower than the comparable 2006 period. The decrease in transportation costs is attributable to strengthening sulphur prices which significantly reduced the cost of disposing of sulphur.
Highpine incurred $61.9 million of capital expenditures in the fourth quarter of 2007 compared to $72.7 million in the fourth quarter of 2006. Highpine drilled 8 (7.2 net) wells consisting of 4 (3.9 net) oil wells and 4 (3.3) gas wells. No dry holes were drilled in the fourth quarter. The 94 percent owned 16-36-048-08W5M long reach well was completed and commenced production on December 21. The well was shut-in at year end awaiting regulatory approval of a production allowable.
Highpine's funds flow per diluted share increased 93 percent in the quarter as a result of higher production volumes and higher realized crude oil prices. Highpine generated net earnings of $19.8 million in the fourth quarter of 2007 as a result of a $22.8 million future tax reduction as a result of enacted Canadian federal tax rate reductions.
Change in Accounting Policies Financial Instruments
Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") section 3855 "Financial Instruments - Recognition and Measurement," section 1530 "Comprehensive Income," section 3865 "Hedges" and section 3861 "Financial Instruments - Disclosure and Presentation". The standards deal with the recognition and measurement of financial instruments and comprehensive income. These standards have been adopted prospectively. Adoption of these standards did not impact January 1, 2007 opening balances. See Note 3 to the consolidated financial statements.
Future Accounting Changes
On December 1, 2006, the CICA issued three new accounting standards: Section 1535, "Capital Disclosures", Section 3862, "Financial Instruments - Disclosures", and Section 3863, "Financial Instruments - Presentation". These new standards will be effective on January 1, 2008.
Section 1535 specifies the disclosure of an entity's objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and if it has not complied, the consequences of such non-compliance. This section is expected to have minimal impact on the Company's financial statements.
Sections 3862 and 3863 specify a revised and enhanced disclosure on financial instruments. These sections will require the Company to increase disclosure on the nature and extent of risks arising from financial instruments and how the entity manages those risks.
Critical Accounting Estimates
The preparation of the Company's financial statements requires management to adopt accounting policies that involve the use of significant estimates and assumptions. These estimates and assumptions are developed based on the best available information and are believed by management to be reasonable under the existing circumstances. New events or additional information may result in the revision of these estimates over time.
Revenues, Royalties and Operating Costs
The Company estimates revenues, royalties and operating costs on production as at specific reporting dates for which actual revenues and costs have not been received.
Capital Expenditures
The Company estimates capital expenditures incurred on projects that are in progress.
Ceiling Test
The carrying amount of property, plant and equipment is reviewed quarterly for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future undiscounted cash flows. The ceiling test calculation is based on estimates of proved and probable reserves, production rates, oil and natural gas prices, royalty rates, future costs and other relevant assumptions. Highpine's December 31, 2007 ceiling test was prepared using cash flows that incorporated the Alberta government's New Royalty Framework as interpreted by management and the Company's reserve evaluators. Changes to the New Royalty Framework could significantly impact future cash flows. By their nature, these estimates are subject to measurement uncertainty and the effects of changes in such estimates in future periods on financial statements could be significant. Any impairment would be charged to earnings.
Depletion, Depreciation and Accretion
Highpine follows CICA accounting guideline AcG-16 on full cost accounting in the oil and natural gas industry to account for oil and natural gas properties. Under this method, all costs associated with the acquisition of, exploration for, and the development of crude oil and natural gas reserves are capitalized and costs associated with production are expensed. The capitalized costs are depleted using the unit-of-production method based on estimated proved reserves using management's best estimate of future prices. Reserves estimates can have a significant impact on earnings, as they are a key component in the calculation of depletion.
Asset Impairment
Producing properties and unproved properties are assessed for impairment annually, or as economic events dictate. The cash flows used in the impairment assessment require management to make estimates and assumptions as to recoverable reserves, future commodity prices and operating costs. Changes in any of the estimates or assumptions could result in an impairment of the carrying value of producing properties and unproved properties.
Asset Retirement Obligations
Asset retirement obligations require that management make estimates and assumptions regarding future liabilities and cash flows involving environmental reclamation and remediation. Estimates of future liabilities and cash flows are subject to uncertainty associated with the method of reclamation and remediation, environmental legislation, the timing of reclamation and remediation activities and the cost of reclamation and remediation activities.
Purchase Price Allocation
Business acquisitions are accounted for by the purchase method of accounting. Under this method, the purchase price is allocated to the assets acquired and the liabilities assumed based on the fair value at the time of acquisition. The excess purchase price over the fair value of identifiable assets and liabilities acquired is goodwill. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant and equipment acquired generally require the most judgment and include estimates of reserves acquired, future commodity prices and discount rates. Future net earnings can be affected as a result of changes in future depletion and depreciation, asset impairment or goodwill impairment.
Goodwill Impairment
Goodwill is subject to impairment tests annually, or as economic events dictate, by comparing the fair value of the reporting entity to its carrying amount, including goodwill. If the fair value of the reporting entity is less than its carrying amount, a goodwill impairment loss is recognized as the excess of the carrying amount of the goodwill over the implied fair value of the goodwill. The determination of fair value requires management to make assumptions and estimates about recoverable reserves, future commodity prices, operating costs, royalty rates, production profiles and discount rates.
Accounting for Stock Options
The Company recognizes compensation expense on options granted pursuant to its stock option plan. Compensation expense is based on the theoretical fair value of each option at its grant date, the estimation of which requires management to make assumptions about the future volatility of the Company's stock price, future interest rates and the timing of optionee's decisions to exercise the options. The effects of a change in one or more of these variables could result in a materially different fair value.
Future Income Taxes
The Company records future income tax liabilities and future income tax assets based on the differences between the carrying amount of assets and liabilities in the consolidated balance sheet and their tax basis using income tax rates substantively enacted at the balance sheet date. As substantively enacted tax rates decline between 2008 and 2012, the determination of the income tax rate to apply to temporary differences requires management to forecast the reversal of temporary differences over the five year period.
Disclosure Controls
Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation that the Company's disclosure controls and procedures were operating effectively during 2007 to provide reasonable assurance that material information related to the Company, including its consolidated subsidiaries, is made known to them by others within those entities.
Internal Controls Over Financial Reporting
Internal controls have been designed to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements together with the other financial information for external purposes in accordance with Canadian GAAP. The Company's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision internal controls over financial reporting related to the Company, including its consolidated subsidiaries.
The Company's Chief Executive Officer and Chief Financial Officer are required to cause the Company to disclose herein any change in the Company's internal control over financial reporting that occurred during the Company's most recent interim period that materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. There were no material changes in the Company's internal controls over financial reporting during the quarter ended December 31, 2007.
It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
Business Risks and Uncertainties
Highpine is exposed to numerous risks and uncertainties associated with the exploration for and development, production and acquisition of crude oil, natural gas and NGL. Primary risks impacting Highpine are as follows:
- Government royalties have a significant impact on Highpine's financial results. If the New Royalty Framework proposed by the Alberta government on October 25, 2007 is enacted as proposed, Highpine's royalty rates are expected to increase significantly commencing in 2009. The increase in royalty rates could result in a reduction of funds available under existing credit facilities and impact the Company's ability to raise funds through capital markets. Higher royalty rates could also make certain of the Company's future prospects uneconomic. - A significant portion of Highpine's portfolio of producing oil and natural gas properties are comprised of sour hydrocarbons. A sour gas leak could result in personal injury or significant damage to oil and gas properties, equipment and the environment. In addition, obtaining drilling licenses for sour hydrocarbons is complex and there is no certainty that attempts to obtain drilling licenses will be successful. - The sour nature of Highpine's production results in significant processing. Other companies operate certain of the processing facilities that Highpine is dependent on. As a result, Highpine has a limited ability to exercise influence over the operation of these assets. Downtime at these facilities has resulted in curtailment of the Company's production in past periods. Downtime at these facilities in the future could result in further curtailments and could significantly impact Highpine's performance. - The prices received for Highpine's crude oil, natural gas and NGL fluctuate due to many factors including local and global market supply and demand, weather patterns, pipeline transportation and political stability. - The long-term commercial success of Highpine depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, existing reserves and the production therefrom will decline over time as such existing reserves are exploited. Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completion and operating costs. - All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. - In 2002, the Government of Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to reduce its greenhouse gas emissions to specified levels. In 2007, the Federal Government announced a new climate change plan that calls for greenhouse gas emissions to be reduced by 20 percent below current levels by 2020. In 2007, the Alberta government introduced legislation to reduce greenhouse gas emission intensity; supporting this, in January of 2008, it announced a new climate change action plan based on three areas: (i) carbon capture and storage; (ii) energy conservation and efficiency; and (iii) greening production through increased investment in clean energy technology. Implementation of strategies for reducing greenhouse gases could have a material impact on the nature of oil and natural gas operations, including those of the Company. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the Company and its operations and financial condition.
These factors should not be considered to be exhaustive. Additional risks are outlined in the Annual Information Form of the Company available on SEDAR.
Selected Annual Information 2007 2006 2005 ------------------------------------------------------------------------- Financial ($000s, except per share amounts) Total revenue(1) 401,297 254,938 141,634 Net earnings (loss) (345,054) 6,953 12,274 Per share - basic (5.09) 0.12 0.35 Per share - diluted (5.09) 0.12 0.34 Funds from operations 193,840 127,440 74,550 Per share - basic 2.86 2.21 2.13 Per share - diluted 2.83 2.17 2.09 Corporate acquisitions - 379,345 257,314 Capital expenditures(2) 199,513 222,214 153,606 Total assets 1,062,576 1,392,911 753,690 Long-term debt 146,675 138,890 - ------------------------------------------------------------------------- Operating Average daily production Oil and NGLs (Bbls/d) 11,332 7,554 3,984 Natural Gas (Mcf/d) 38,426 25,350 13,823 Total (BOE/d) 17,736 11,779 6,288 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Summary of Quarterly Results ------------------------------------------------------------------------- 2007 Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Financial ($000s, except per share amounts) Total revenue(1) 122,178 89,439 103,769 85,911 Net earnings (loss) 19,805 (359,513) 1,060 (6,406) Per share - basic 0.29 (5.30) 0.02 (0.09) Per share - diluted 0.29 (5.30) 0.02 (0.09) Funds from operations 58,357 43,984 46,869 44,630 Per share - basic 0.86 0.65 0.69 0.66 Per share - diluted 0.85 0.64 0.68 0.65 Corporate acquisitions - - - - Capital expenditures(2) 61,948 37,073 24,670 75,822 Total assets 1,062,576 1,044,815 1,415,081 1,421,510 Long-term debt 146,675 150,414 171,943 157,870 ------------------------------------------------------------------------- Operating Average daily production Oil and NGLs (Bbls/d) 13,394 10,143 11,025 10,750 Natural Gas (Mcf/d) 37,930 34,637 41,449 39,749 Total (BOE/d) 19,716 15,916 17,933 17,375 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2006 Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Financial ($000s, except per share amounts) Total revenue(1) 67,552 60,205 62,765 64,416 Net earnings (loss) (5,446) 514 10,594 1,291 Per share - basic (0.08) 0.01 0.20 0.03 Per share - diluted (0.08) 0.01 0.20 0.03 Funds from operations 29,973 31,171 34,750 31,546 Per share - basic 0.44 0.50 0.66 0.66 Per share - diluted 0.44 0.49 0.65 0.65 Corporate acquisitions - 289,694 - 89,651 Capital expenditures(2) 72,711 56,144 46,590 46,769 Total assets 1,392,911 1,361,249 920,941 910,157 Long-term debt 138,890 113,287 - - ------------------------------------------------------------------------- Operating Average daily production Oil and NGLs (Bbls/d) 8,653 6,675 6,940 7,950 Natural Gas (Mcf/d) 30,221 24,837 25,562 20,681 Total (BOE/d) 13,690 10,814 11,201 11,397 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Total revenue is after realized and unrealized hedging losses and gains. (2) Capital expenditures are net of property dispositions. Discussion of Quarterly Trends
Total revenue of the Company has generally trended with average daily production levels and commodity prices. During the second and third quarter of 2006, production was negatively impacted as a result of volumes being temporarily shut-in due to reservoir operating pressures being below the required minimum in certain pools. Water injection schemes were implemented in the third and fourth quarter of 2006 which brought previously shut-in production back on-stream. Production continued to increase in the fourth quarter of 2006 and the first two quarters of 2007 from the acquisition of Kick in August 2006 combined with production generated from the Company's drilling program. In the third quarter of 2007, production was negatively impacted by scheduled and unscheduled facility turnarounds. Production increased in the fourth quarter of 2007 as facility downtime was reduced.
Net earnings for the fourth quarter of 2007 include a $22.8 million future tax reduction as a result of substantively enacted federal rate reductions. Net loss for the third quarter of 2007 includes a $358.1 million non-recurring non-cash charge as a result of the impairment of goodwill. Net earnings for the second quarter of 2006 include a $9.1 million future tax reduction as a result of substantively enacted federal and provincial income tax reductions.
CONSOLIDATED BALANCE SHEETS ------------------------------------------------------------------------- December 31, December 31, 2007 2006 ------------------------------------------------------------------------- ($000s)(unaudited) Assets Current assets Accounts receivable 75,772 54,944 Prepaid expenses and deposits 4,642 2,928 Financial instruments (notes 3 and 11) 406 3,194 ------------------------------------------------------------------------- 80,820 61,066 Property, plant and equipment (note 6) 980,906 972,599 Long-term investment (notes 3 and 7) 850 1,150 Goodwill (note 5) - 358,096 ------------------------------------------------------------------------- 1,062,576 1,392,911 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities and Shareholders' Equity Current liabilities Accounts payable and accrued liabilities 108,560 88,552 Future income taxes (note 13) 105 970 ------------------------------------------------------------------------- 108,665 89,522 Long-term debt (note 8) 146,675 138,890 Future income taxes (note 13) 131,249 150,832 Asset retirement obligations (note 9) 11,378 11,258 Deferred lease inducements 324 408 Shareholders' equity Share capital (note 10) 959,456 957,186 Contributed surplus (note 10) 15,030 9,962 Retained earnings (deficit) (310,201) 34,853 ------------------------------------------------------------------------- 664,285 1,002,001 Commitments (note 12) ------------------------------------------------------------------------- 1,062,576 1,392,911 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME AND RETAINED EARNINGS (DEFICIT) ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 2007 2006 ------------------------------------------------------------------------- ($000s, except per share amounts) (unaudited) Revenues Oil and natural gas revenues 125,553 66,601 403,598 247,804 Royalties, net of ARTC (36,515) (18,635) (116,784) (70,529) Financial instruments (note 11) Realized (losses) gains (3,474) 727 487 4,703 Unrealized (losses) gains 99 224 (2,788) 2,431 ------------------------------------------------------------------------- 85,663 48,917 284,513 184,409 Expenses Operating costs 21,690 13,124 66,937 36,839 Transportation costs 426 778 4,925 3,069 General and administrative 2,683 3,209 12,171 9,682 Depletion, depreciation and accretion 56,569 36,902 194,207 125,306 Interest and finance costs 2,433 1,588 9,390 4,991 Stock-based compensation (note 10) 1,140 1,333 4,463 5,677 Impairment of goodwill (note 5) - - 358,096 - Impairment of long-term investment (note 7) 300 - 300 - ------------------------------------------------------------------------- 85,241 56,934 650,489 185,564 ------------------------------------------------------------------------- Earnings (loss) before taxes 422 (8,017) (365,976) (1,155) ------------------------------------------------------------------------- Taxes (reduction) (note 13) Current (46) - (46) (127) Future (19,337) (2,571) (20,876) (7,981) ------------------------------------------------------------------------- (19,383) (2,571) (20,922) (8,108) ------------------------------------------------------------------------- Net earnings (loss) 19,805 (5,446) (345,054) 6,953 Retained earnings (deficit), beginning of period (330,006) 40,299 34,853 27,900 ------------------------------------------------------------------------- Retained earnings (deficit), end of period (310,201) 34,853 (310,201) 34,853 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net earnings (loss) per share (note 10) Basic $ 0.29 $ (0.08) $ (5.09) $ 0.12 Diluted $ 0.29 $ (0.08) $ (5.09) $ 0.12 ------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. CONSOLIDATED STATEMENTS OF CASH FLOWS ------------------------------------------------------------------------- Three months ended Twelve months ended December 31, December 31, 2007 2006 2007 2006 ------------------------------------------------------------------------- ($000s) (unaudited) Cash provided by (used in): Operating Activities Net earnings (loss) 19,805 (5,446) (345,054) 6,953 Items not involving cash: Depletion, depreciation and accretion 56,569 36,902 194,207 125,306 Future income tax reduction (19,337) (2,571) (20,876) (7,981) Stock-based compensation 1,140 1,333 4,463 5,677 Unrealized losses (gains) on financial instruments (99) (224) 2,788 (2,431) Amortization of deferred lease inducements (21) (21) (84) (84) Impairment of goodwill (note 5) - - 358,096 - Impairment of long-term investment (note 7) 300 - 300 - Abandonment expenditures (456) (316) (1,472) (368) Change in non-cash operating working capital (1,989) 9,452 (5,799) (18,018) ------------------------------------------------------------------------- 55,912 39,109 186,569 109,054 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Financing Activities Common shares issued for cash - - - 100,620 Share issue costs - - - (4,606) Proceeds on exercise of stock options 31 52 1,894 1,202 Increase (decrease) in bank indebtedness (15,591) 25,603 7,785 4,618 ------------------------------------------------------------------------- (15,560) 25,655 9,679 101,834 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Investing Activities Property, plant and equipment additions (61,537) (72,806) (202,734) (194,753) Proceeds on disposal of property, plant and equipment 84 - 3,716 - Property acquisitions (495) 95 (495) (27,461) Purchase of investments - - - (150) Net cash paid on business combination - - - (1,091)
Deferred charges - - - 251
