Highpine Oil & Gas Limited Announces Third Quarter 2007 Financial and Operational Results
CALGARY, Nov. 8 /PRNewswire-FirstCall/ — Highpine Oil & Gas Limited (TSX: HPX) (“Highpine” or the “Company”) announces its financial and operational results for the third quarter ended September 30, 2007 and provides an operational update:
FINANCIAL AND OPERATING RESULTS ————————————————————————- Three months ended Nine months ended ($000s, except September 30, September 30, per share and % % share numbers) 2007 2006 Change 2007 2006 Change ————————————————————————- Financial Total revenue(1) 89,439 60,205 49 279,119 187,386 49 Cash from operations(2) 43,984 31,171 41 135,483 97,467 39 Per share – diluted 0.65 0.49 33 2.00 1.76 14 Net earnings (loss)(3) (359,513) 514 – (364,859) 12,399 – Per share – diluted (5.30) 0.01 – (5.39) 0.22 – Net debt(4) 170,805 123,758 38 170,805 123,758 38 Total assets 1,044,815 1,361,249 (23) 1,044,815 1,361,249 (23) Capital expenditures(5) 37,073 56,144 (34) 137,565 149,503 (8) Total shares outstanding (#) 67,878 67,641 – 67,878 67,641 – Weighted average shares Outstanding – diluted (#) 67,856 63,356 7 67,735 55,353 22 ————————————————————————- Operating Average daily production Crude oil and NGLs (bbls/d) 10,143 6,675 52 10,637 7,184 48 Natural gas (mcf/d) 34,637 24,837 39 38,593 23,708 63 ————————————————————————- Total (boe/d) 15,916 10,814 47 17,069 11,135 53 ————————————————————————- Average selling prices(6) Crude oil and NGLs ($/bbl) 75.28 70.71 6 68.32 69.37 (2) Natural gas ($/mcf) 6.07 6.27 (3) 7.56 6.98 8 ————————————————————————- Total ($/boe) 61.20 58.05 5 59.67 59.61 – ————————————————————————- Wells drilled – gross (net) (#) Oil 3(2.0) 3(2.5) – 6(4.2) 7(5.3) – Natural Gas 3(2.0) 12(8.8) – 12(7.9) 35(20.4) – Abandoned/ other 2(1.2) 4(3.1) – 8(5.6) 13(7.7) – ————————————————————————- Total 8(5.2) 19(14.4) – 26(17.7) 55(33.4) – Drilling success rate (%) 76 85 – 78 82 – ————————————————————————- Operating netback ($/boe) Oil and natural gas sales 61.20 58.05 5 59.67 59.61 – Royalties (17.88) (14.02) 28 (17.22) (17.07) 1 Operating costs (9.76) (9.52) 3 (9.71) (7.80) 24 Transportation costs (0.76) (0.98) (22) (0.96) (0.75) 28 Realized hedging gain 0.80 1.68 (52) 0.85 1.31 (35) ————————————————————————- Operating netback 33.60 35.21 (5) 32.63 35.30 (8) ————————————————————————- ————————————————————————- (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. THIRD QUARTER OPERATIONAL HIGHLIGHTS – 2007 – For the nine months period ending September 30, 2007, production averaged 17,069, compared with 11,135 in the 2006 period. Hydrocarbon production averaged 15,916 boe/d for the quarter, consisting of 10,143 bbls/d of oil and NGL’s and 34.64 mmcf/d of gas, compared to 10,814 boe/d in the third quarter of 2006, an increase of 47 percent. – Total revenue increased 49 percent to $89.4 million from $60.2 million in the comparable 2006 period. – Cash from operations increased 41 percent to $44.0 million from $31.2 million in the third quarter of 2006. Cash flow per diluted share was $0.65. – Operating netbacks after realized hedging remained strong at $33.60/boe for the third quarter of 2007 and $32.63/boe for the first nine months of 2007. – Capital expenditures of $37.1 million were incurred focused mainly in the Pembina Nisku Fairway. – Highpine obtained six (6) critical sour Nisku well licences in the Pembina area during the third quarter. Currently, twenty five (25) Nisku well licence applications are awaiting approval at the Energy Utilities Board (“EUB”) and we have ten (10) approved licences in inventory. – Eight (8) wells were drilled during the third quarter, resulting in 3 (2.0 net) oil wells, 3 (2.0 net) gas wells and 2 (1.2 net) dry holes, resulting in a 76 percent drilling success ratio. During the first nine months of 2007, 26 (17.7 net) wells were drilled resulting in 6 (4.2 net) oil wells, 12 (7.9 net) gas wells, 2 (1.7 net) service wells and 6 (3.9 net) dry holes which resulted in a 78 percent drilling success ratio. – Highpine reduced its total debt (including working capital deficiency) to $170.8 million from $178.0 million at the end of the second quarter of 2007. The amount of the bank loan at the end of the third quarter was $162.3 million. – Highpine reduced its third quarter 2007 net general & administrative expenses per boe to $1.87, 18 percent lower than the third quarter of 2006. OPERATIONS
During the third quarter, production averaged 15,916 boe/d, despite multiple third party gas plant turnarounds and continued production curtailments through these facilities. Highpine successfully completed the turnaround of its operated Violet Grove battery concurrent with the third party gas plant turnarounds. During October, production averaged 19,185 boe/d based on field estimates. Additional optimization of several new tie-ins will be completed prior to year-end; as well third party gas processing facilities are expected to be fully operational through the balance of the year.
Since June, Highpine has cased five (4.25 net) Nisku wells in the Pembina Nisku Fairway. Two (1.82 net) wells have been completed as condensate rich gas wells, one (1) has been completed as an oil well and 2.0 (1.425 net) are waiting on completion. One of the wells currently being completed is the 4200 m measured depth long reach well into the up-dip end of the Pembina Nisku WW Pool. This well encountered a thick porous reef as expected, with no hydrocarbon-water interface and is currently being completed as an oil well. Production facilities are currently being constructed.
A new Cretaceous 100% well at Joffre is on-stream at rates in excess of 500 mcf/d of gas.
A recently completed 50% interest Cretaceous gas well at Ansell is on-stream at a restricted gross rate of 2.8 mmcf/d, plus natural gas liquids. We are currently completing a nearby well which indicates similar potential production rates. Production rates at Ansell will be restricted until facility modifications are completed in March, 2008.
Currently, one (1) drilling rig is active on a Highpine operated well targeting the Nisku formation. The Company plans to have 2 rigs drilling through the balance of 2007 targeting the Nisku formation.
Going forward into the fourth quarter, we will complete and tie-in 4 recently drilled Nisku wells including the long reach well at 16-36-48-8W5.
Highpine has been successful in obtaining five (5) critical sour Nisku well licences in the Pembina area during the fourth quarter. Highpine is working on additional Nisku well licence applications that will be submitted to the EUB for approval during the fourth quarter and the first quarter of 2008. The Company is currently in a EUB public hearing for two Nisku wells located near the community of Rocky Rapids and has requested one additional EUB hearing for five (5) Nisku well locations.
FINANCIAL
A decline in the Company’s share price that in part, can be attributed to the recent Alberta Royalty Announcement, resulted in a $358.1 million goodwill impairment during the third quarter. Goodwill, arising from corporate acquisitions made in prior years, represents the excess of the purchase price paid for the acquisitions over the fair value of the net assets acquired. The $358.1 million impairment was recorded as a non-cash charge to earnings for the quarter ended September 30, 2007. The goodwill write-down is not an indication of the underlying value of the Company’s properties.
ALBERTA ROYALTY ANNOUNCEMENT
The Alberta government recently announced changes to the royalties payable on all crown mineral rights owned by the province. In the event the Alberta Government proposed royalty framework is enacted, on January 1, 2009 the crown royalty payable on conventional oil production will rise from approximately 30% to 50% for wells which produce above 60 bbl/d at today’s oil prices. Based on the interpretation of publicly available information, Highpine estimates that the new royalty would reduce cash flow by 29%, depending on average well monthly production rates used and an oil price of US$70 WTI per barrel. Other factors which will affect the calculation include the actual legislation enacted, the individual well production rates, commodity prices, foreign exchange rates, product mix, and the percentage of production from Alberta after January 1, 2009. The Company is still working to enact certain reductions to the conventional oil royalty based on the depth of well, which is similar to the proposed rules for deep gas wells.
Highpine strongly agrees with other Alberta exploration companies that the royalty changes are discriminatory for companies engaged in high-risk deep conventional oil exploration such as the Company’s Pembina Nisku program. The new royalties do not strike a balance between risk and reward in our composite drilling program. The Company will adjust its drilling program by increasing target size to find that new balance. The Company is likely to make further adjustments to its capital program as additional information becomes available. In making its announcement, the Government of Alberta indicated that it would address any anomalies created by the proposals. Highpine believes that the effect of the changes to the royalty regime governing light oil will not only adversely affect Highpine, but will result in reduced royalty revenue to the Province, as exploration is curtailed. Highpine continues to discuss with the Province the effect of these proposals on all stakeholders with a view to arriving at a solution which is fair to all parties.
COMMENTS AND OUTLOOK
As our shareholders know, our journey to the 20,000 barrel per day plateau has been slower than previously forecast. We are there now. Our cash flow at current prices is strong. What we didn’t need at this time was for the Alberta Government to change the royalty regime under which we have been operating. As presented it is penal to Highpine. Of the extra $1.4 billion projected to be collected by the Alberta Treasury, $460 million will come from conventional oil. Our internal projections indicate that of the provincial increase, over 9% will come from Highpine alone. Clearly this is unfair, unreasonable and surely must be an unintended consequence of these royalty changes. We have been advancing and intend to further advance our case along these lines directly to the Energy Minister.
In the meantime, we intend to reduce our budget, but by no means drastically. We have many profitable projects under the current rules and still some very exciting new pool wildcats to drill. Over the years, the Alberta Government has been encouraging and supportive of smaller energy companies, particularly with Canadian roots. As optimists, we believe sooner or later, everyone will come to their senses and legislate a system that is fair for Highpine and other similar companies.
In the short term, we do have to face reality. The Highpine share price has dropped to a level that from an accounting standpoint requires a write-off of the full amount of goodwill on our balance sheet. This amounts to $358.1 million, but this has no effect on our cash balances, cash flow, liquidity, or banking status.
Operationally, production is still steadily rising, our drilling results have been excellent, and our new prospects are better than ever.
CONFERENCE CALL
Highpine will host a conference call to discuss its financial and operational results at 9:00 am MST, Friday, November 9, 2007.
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 December 1, 2007 in North America Toll Free: 1-800-319-6413, Pin Code: 2090 followed by the number sign.
MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (MD&A) is dated and based on information at November 7, 2007. This MD&A has been prepared by management and should be read in conjunction with the unaudited interim consolidated financial statements for the nine months ended September 30, 2007 and audited consolidated financial statements for the years ended December 31, 2006 and 2005 for a complete understanding of the financial position and results of operations of Highpine Oil & Gas Limited (“Highpine” or the “Company”). The unaudited interim 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.
Certain information set forth in this MD&A contains forward-looking statements including expectations of future production, management’s assessment of the effect of changes to royalty rates in Alberta, procurement of drilling permits, plans for and results of exploration and development activities and other operational developments and components of cash flow and earnings. Readers are cautioned that assumptions used in the preparation of such statements may prove to be incorrect. Events or circumstances may cause actual results to differ materially from those predicted, as a result of numerous known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company. These risks include, but are not limited to: the effect of changes in royalty rates, the risks associated with the oil and natural gas industry, commodity prices, and exchange rate changes. Industry related risks include, but are not limited to: operational risks in exploration, development and production of oil and natural gas and production risks associated with sour hydrocarbons, dependence on third-party owned and operated production facilities, availability of skilled personnel and services, failure to obtain industry partner, regulatory and other third-party consents and approvals, delays or changes in plans, risks associated with the uncertainty of reserve estimates, health and safety risks and the uncertainty of estimates and projections of reserves, production, costs and expenses. The risks outlined above should not be construed as exhaustive. Readers are cautioned not to place undue reliance on these statements. The Company undertakes no obligation to update or revise any forward-looking statements except as required by applicable securities laws.
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 months ended Nine months ended September 30, September 30, 2007 2006 2007 2006 ————————————————————————- ($000s) Cash flow from operating activities 38,014 9,247 130,657 69,945 Change in non-cash operating working capital 5,699 21,918 3,810 27,470 Abandonment expenditures 271 6 1,016 52 ————————————————————————- Funds from operations 43,984 31,171 135,483 97,467 ————————————————————————- ————————————————————————-
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 Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- ($000s) Crude oil and natural gas liquids (NGLs) revenue 70,252 43,421 62 198,376 136,040 46 Natural gas revenue 19,357 14,332 35 79,669 45,163 76 ————————————————————————- 89,609 57,753 55 278,045 181,203 53 Realized hedging gain 1,166 1,668 (30) 3,961 3,976 – Unrealized hedging gain (loss) (1,336) 784 – (2,887) 2,207 – ————————————————————————- Total oil and natural gas revenue 89,439 60,205 49 279,119 187,386 49 ————————————————————————- ————————————————————————-
For the nine months ended September 30, 2007 total oil and natural gas revenue increased to $279.1 million from $187.4 million for the nine months ended September 30, 2006 due to production volume increases. Total oil and natural gas revenue was negatively impacted by $2.9 million of unrealized hedging losses compared to $2.2 million of unrealized hedging gains in the comparative nine month period.
For the three months ended September 30, 2007, total oil and gas revenue increased to $89.4 million from $60.2 million for the three months ended September 30, 2006 due to production volume increases.
Production ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Daily Production Crude oil and NGLs (bbls/d) 10,143 6,675 52 10,637 7,184 48 Natural gas (mcf/d) 34,637 24,837 39 38,593 23,708 63 ————————————————————————- Boe/d 15,916 10,814 47 17,069 11,135 53 ————————————————————————- ————————————————————————- Production Mix Crude oil and NGLs 64% 62% 3 62% 65% (5) Natural gas 36% 38% (5) 38% 35% 9 ————————————————————————- 100% 100% – 100% 100% – ————————————————————————- ————————————————————————- ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- (boe/d) Daily Production by Area Pembina Nisku Fairway 12,163 7,381 65 13,149 7,818 68 West Central Alberta Gas Fairway 2,996 2,825 6 3,187 2,676 19 Bantry/Retlaw 650 452 44 606 469 29 Other 107 156 (31) 127 172 (26) ————————————————————————- Total 15,916 10,814 47 17,069 11,135 53 ————————————————————————- ————————————————————————- Prior periods have been reclassified to conform with current period presentation.
Production for the nine months ended September 30, 2007 increased 53 percent to 17,069 boe/d from 11,135 boe/d for the nine months ended September 30, 2006. The increase is attributable to production from the acquisition of Kick Energy Corporation (“Kick”) on August 1, 2006 and new production from the Company’s drilling program.
Production for the three months ended September 30, 2007 increased 47 percent to 15,916 boe/d from 10,814 boe/d for the three months ended September 30, 2006. The increase in production is a result of bringing new wells from the Company’s drilling program on stream.
Production for the third quarter of 2007 decreased 11 percent to 15,916 boe/d from 17,933 boe/d in the second quarter of 2007. The decrease is attributable to a scheduled facility turnaround at Highpine’s Violet Grove oil battery which reduced production by approximately 6,000 boe/d for three weeks combined with unscheduled turnarounds at various non-operated facilities.
Pricing ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Selling Prices Before Hedges Crude oil and NGLs ($/bbl) 75.28 70.71 6 68.32 69.37 (2) Natural gas ($/mcf) 6.07 6.27 (3) 7.56 6.98 8 ————————————————————————- Total combined ($/boe) 61.20 58.05 5 59.67 59.61 – ————————————————————————- ————————————————————————- ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Benchmark Prices WTI oil (US$/bbl) 75.38 70.48 7 66.08 68.22 (3) US$/Cdn$ exchange rate 0.96 0.89 8 0.91 0.88 3 AECO natural gas ($/mcf) (monthly) 5.61 6.03 (7) 6.81 7.19 (5) ————————————————————————- ————————————————————————-
An increase in the WTI benchmark price for crude oil of 7 percent resulted in a higher realized price for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. The increase in the WTI benchmark price was partially offset by strengthening of the Canadian dollar relative to the US dollar. Continued strengthening of the Canadian dollar subsequent to September 30, 2007 will continue to erode increases in the WTI benchmark price. Average AECO prices were 7 percent lower in the third quarter of 2007 compared to the third quarter of 2006 resulting in lower realized natural gas prices.
The WTI benchmark price for crude oil was 3 percent lower for the first nine months of 2007 compared to the first nine months of 2006 resulting in lower realized prices. Highpine’s realized natural gas price increased by 8 percent for the first nine months of 2007 in contrast to a decrease in average AECO prices as a result of certain Highpine contracts being based on the daily index which increased over the comparative period.
Commodity Price Risk Management
Highpine’s ability to execute its business strategy is dependent on generating cash flow that can be reinvested into its capital program. The Company utilizes financial and physical commodity price hedges to protect cash flow against commodity price volatility. Highpine may enter into commodity price hedges to a maximum of 50 percent of budgeted production.
————————————————————————- Nine months ended September 30, 2007 2006 Crude Oil & Natural Total Total NGLs (bbl) Gas (mcf) (boe) (boe) ————————————————————————- Average volumes hedged (per day) 5,500 13,889 7,815 4,487 Percent of production hedged 52% 36% 46% 40% Realized hedging gain ($) 0.42 0.26 0.85 1.31 ————————————————————————- ————————————————————————-
For the nine months ended September 30, 2007, Highpine realized a $2.7 million natural gas hedging gain and a $1.2 million crude oil hedging gain. For the nine months ended September 30, 2006, Highpine realized a $4.7 million natural gas hedging gain and a $0.8 million crude oil hedging loss.
For the three months ended September 30, 2007, Highpine realized a $1.3 million unrealized hedging loss primarily related to crude oil contracts.
————————————————————————- Nine months ended September 30, 2007 2006 Crude Oil Natural & NGLs Gas Total Total ————————————————————————- ($000s) Realized hedging gain 1,230 2,731 3,961 3,976 Unrealized hedging gain (loss) (3,033) 146 (2,887) 2,207 ————————————————————————- Total hedging gain (loss) (1,803) 2,877 1,074 6,183 ————————————————————————- ————————————————————————- The following contracts were outstanding at September 30, 2007: ————————————————————————- Term Contract Volume Fixed Price ————————————————————————- Jan 07 to Dec 07 Oil Collar 1,750 bbls/d US $55.00 to $86.15/bbl Jan 07 to Dec 07 Oil Collar 1,750 bbls/d US $60.00 to $80.70/bbl Jan 07 to Dec 07 Oil Swap 500 bbls/d Cdn $73.00/bbl Jan 07 to Dec 07 Oil Swap 500 bbls/d Cdn $73.70/bbl Jan 07 to Dec 07 Oil Swap 500 bbls/d Cdn $74.70/bbl Jan 07 to Dec 07 Oil Swap 500 bbls/d Cdn $75.82/bbl Jan 07 to Dec 07 Natural Gas Swap 2,500 GJs/d Cdn $7.55/GJ Jan 07 to Dec 07 Natural Gas Swap 2,500 GJs/d Cdn $7.62/GJ 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 September 30, 2007, the unrealized mark-to-market loss on outstanding crude oil contracts was $1.9 million and the unrealized mark-to-market gain on outstanding natural gas contracts was $2.2 million.
Royalty Expense ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Total royalties, net of ARTC 26,190 13,948 88 80,269 51,894 55 ($000s) As a percent of oil and natural gas sales (before hedging) 29% 24% 21 29% 29% – $/boe 17.88 14.02 28 17.22 17.07 1 ————————————————————————- ————————————————————————-
Royalty rates as a percentage of oil and natural gas sales were higher in the third quarter of 2007 compared to the third quarter of 2006 as a result of a GCA adjustment received in the third quarter of 2006 related to the prior year that reduced the 2006 royalty expense.
Royalty rates as a percentage of oil and natural gas sales were consistent during the first nine months of 2007 compared to the first nine 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 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 Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Operating costs ($000s) 14,287 9,472 51 45,247 23,715 91 $/boe 9.76 9.52 3 9.71 7.80 24 ————————————————————————- ————————————————————————-
For the nine and three months ended September 30, 2007, operating costs on a per boe basis increased 24 percent and 3 percent respectively compared to the comparative 2006 periods. The increases were a result of higher processing costs on increased Pembina sour production realized in 2007 including higher processing charges on volumes processed at third party facilities. In addition, the Company incurred increased workover costs in 2007 as well as the turnaround costs on the Violet Grove oil battery.
Transportation Costs ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Transportation costs ($000s) 1,107 979 13 4,499 2,291 96 $/boe 0.76 0.98 (22) 0.96 0.75 28 ————————————————————————- ————————————————————————-
For the nine months ended September 30, 2007, transportation costs on a per boe basis increased 28 percent compared to the comparative 2006 period. The increase is attributable to higher sulphur transportation charges as a result of the increase in sour oil production combined with incremental costs due to railway interruptions during 2007.
For the three months ended September 30, 2007, transportation costs on a per boe basis decreased 22 percent compared to the comparative 2006 period as a result of increasing global demand for sulphur which reduced the cost of disposal.
Operating Netback ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- ($/boe) Sales price before hedging 61.20 58.05 5 59.67 59.61 – Royalties (17.88) (14.02) 28 (17.22) (17.07) 1 Operating costs (9.76) (9.52) 3 (9.71) (7.80) 24 Transportation costs (0.76) (0.98) (22) (0.96) (0.75) 28 ————————————————————————- Netback before hedges 32.80 33.53 (2) 31.78 33.99 (7) Realized hedging gain 0.80 1.68 (52) 0.85 1.31 (35) ————————————————————————- Operating netback 33.60 35.21 (5) 32.63 35.30 (8) ————————————————————————- ————————————————————————-
Operating netback before realized hedging gains was $32.80/boe for the three months ended September 30, 2007 compared to $33.53/boe for the three months ended September 30, 2006. The $0.73/boe decrease is primarily attributable to higher operating costs as a result of increases in processing costs relating to increased sour oil production combined with higher workover expenditures.
Operating netback before realized hedging gains was $31.78/boe for the nine months ended September 30, 2007 compared to $33.99/boe for the nine months ended September 30, 2006. The 7 percent decrease was due to higher operating and transportation costs.
General and Administrative Expenses ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Gross expenses ($000s) 3,578 3,005 19 11,898 8,495 40 Capitalized ($000s) (844) (724) 17 (2,410) (2,022) 19 ————————————————————————- Net expenses ($000s) 2,734 2,281 20 9,488 6,473 47 ————————————————————————- ————————————————————————- $/boe 1.87 2.29 (18) 2.04 2.13 (4) percent capitalized 24% 24% – 20% 24% (17) ————————————————————————- ————————————————————————-
Gross expenses increased 40 percent to $11.9 million in the first nine months of 2007 from $8.5 million in the first nine months of 2006 as a result of staff increases and employee severance costs incurred. At September 30, 2007, Highpine had 61 Calgary based office employees compared to 55 at September 30, 2006. On a per boe basis, general and administrative expenses decreased 4 percent to $2.04/boe from $2.13/boe in the first nine months of 2006.
Net expenses decreased 20 percent from $3.4 million in the second quarter of 2007 to $2.7 million in the third quarter of 2007 as a result of severance costs incurred in the second quarter of 2007.
Stock-Based Compensation
Stock-based compensation expense totaled $3.3 million in the first nine months of 2007 compared to $4.3 million in the first nine months of 2006. The decrease is attributable to options that were cancelled in the second quarter 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 the first nine months of 2007 were $7.0 million versus $3.4 million in the first nine months of 2006. This increase was primarily due to higher average debt levels.
Depletion, Depreciation and Accretion ————————————————————————- Three months ended Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Depletion and depreciation ($000s) 42,636 29,298 46 136,961 87,945 56 Accretion of asset retirement obligation ($000s) 226 191 18 677 459 47 ————————————————————————- ————————————————————————- Total DD&A 42,862 29,489 45 137,638 88,404 56 ————————————————————————- ————————————————————————- DD&A rate $/boe $29.27 $29.64 (1) $29.54 $29.08 2 ————————————————————————- ————————————————————————-
The depletion, depreciation, and accretion (DD&A) rate of $29.54 per boe for the nine months ended September 30, 2007 was comparable to the $29.08 per boe for the nine months ended September 30, 2006.
Income Taxes
The Company did not incur any cash taxes during the first nine months of 2007. For 2007 and subsequent years, Crown charges are fully deductible for income tax purposes. Resource allowance which was intended to compensate taxpayers for non-deductible Crown charges was eliminated in 2007.
Although current tax horizons depend on product prices, production levels and the nature, magnitude and timing of capital expenditures, the Company currently believes no cash income tax will be payable in 2007 or 2008.
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 of the segment is compared to its fair value. When the carrying amount of the segment 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 Nine months ended September 30, September 30, % % 2007 2006 Change 2007 2006 Change ————————————————————————- Funds from operations ($000s) 43,984 31,171 41 135,483 97,467 39 Per diluted share ($) 0.65 0.49 33 2.00 1.76 14 Net earnings (loss) ($000s) (359,513) 514 – (364,859) 12,399 – Per diluted share ($) (5.30) 0.01 – (5.39) 0.22 – ————————————————————————- ————————————————————————-
For the nine months ended September 30, 2007, funds from operations increased 39 percent to $135.5 million from $97.5 million for the nine months ended September 30, 2006 due to production increases realized. Funds from operations per diluted share increased 14 percent to $2.00.
During the first nine months of 2007, Highpine incurred a net loss of $364.9 million, compared to net earnings of $12.4 million for the nine months ended September 30, 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 nine months ended September 30, 2006 included a $9.1 million non-recurring future tax reduction realized as a result of enacted Canadian federal and Alberta tax rate reductions.
The NRF is not effective until January 1, 2009 and as such funds from operations and net earnings for the years ending December 31, 2007 and 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 USD$70/bbl and AECO CDN $6.00/MMbtu and using a par foreign exchange ratio. In addition, an increase in forecast royalty rates used in the Company’s ceiling test calculation could result in a write-down in a future period.
Liquidity and Capital Resources
At September 30, 2007, the Company had a revolving term credit facility of $230 million and a demand operating credit facility of $20 million with $162 million drawn against these facilities, thereby providing remaining credit capacity of $88 million. At September 30, 2007, the Company had a working capital deficiency of $8.5 million and net debt of $170.8 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 fourth quarter and first quarter. The Company’s working capital deficiency is funded from funds available from existing credit facilities.
————————————————————————- As at September 30, December 31, 2007 2006 ————————————————————————- ($000s) Capitalization Bank debt 162,266 138,890 Working capital deficiency(1) 8,539 30,680 ————————————————————————- Net debt 170,805 169,570 ————————————————————————- ————————————————————————- Shares outstanding (#) 67,878 67,648 Market price at end of period ($) 10.20 15.70 Market capitalization 692,356 1,062,074 ————————————————————————- Total capitalization 863,161 1,231,644 ————————————————————————- ————————————————————————- Net debt as a percent of total capitalization 20% 14% ————————————————————————- ————————————————————————- Annualized funds from operations 180,644 127,440 ————————————————————————- ————————————————————————- Net debt to annualized funds from operations ratio 0.95 1.33 ————————————————————————- ————————————————————————- (1) Working capital excludes unrealized financial instruments.
Expenditures to be incurred on Highpine’s remaining 2007 capital budget are expected to be funded from the Company’s credit facilities and funds from operations. The Company is currently evaluating future capital expenditures in light of the recommendations in the NRF.
At November 7, 2007, the Company’s bank debt was approximately $167 million. The Company’s lenders review the credit facilities semi-annually and as a result of the NRF it is expected that the maximum funds available under the facilities may be reduced.
Capital Expenditures
Capital expenditures, excluding corporate acquisitions, property acquisitions, and property dispositions totaled $141.2 million for the nine months ended September 30, 2007 compared to $121.9 million for the nine months ended September 30, 2006. The Company’s capital program is heavily weighted to the Pembina Nisku fairway which accounted for 89 percent of capital expenditures for the nine months ended September 30, 2007. During the third quarter of 2007, the Company disposed of undeveloped properties in a non-core area for proceeds of $3.6 million.
————————————————————————- Nine months ended September 30, 2007 2006 % Change ————————————————————————- ($000s) Land 10,770 16,148 (33) Geologic and geophysical 7,308 6,440 13 Drilling and completions 79,800 71,159 12 Facilities and equipment 40,857 25,896 58 Capitalized general and administrative 2,410 2,022 19 Office and other 52 207 (75) ————————————————————————- Total capital expenditures 141,197 121,872 16 ————————————————————————- Property acquisitions – 27,631 (100) ————————————————————————- Property dispositions (3,632) – 100 ————————————————————————- Corporate acquisitions(1) – 440,895 (100) ————————————————————————- Total capital expenditures and acquisitions 137,565 590,398 (77) ————————————————————————- ————————————————————————- (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 November 7, 2007, 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 4.9 million class A common shares with an average exercise price of $10.72 per share.
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 2 to the consolidated financial statements.
Critical Accounting Estimates
The preparation of the Company’s consolidated 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.
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 September 30, 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 NGLs. Primary risks include:
– Changes in royalty rates; – Uncertainty associated with obtaining drilling licences and other consents and approvals; – Finding and producing reserves economically; – Production risks associated with sour hydrocarbons; – Marketing reserves at acceptable prices; and – Operating with minimal environmental impact.
Highpine strives to minimize and manage these risks in a number of ways, including:
– Employing qualified professional and technical staff; – Communicating openly with members of the public regarding its activities; – Concentrating in a limited number of areas; – Utilizing the latest technology for finding and developing reserves; – Constructing quality, environmentally sensitive, safe production facilities; – Maximizing operational control of drilling and producing operations; and – Minimizing commodity price risk through strategic hedging. Environmental Risks ——————-
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. There has been much public debate with respect to Canada’s ability to meet these targets and the Government’s strategy or alternative strategies with respect to climate change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases whether to meet the limits required by the Protocol or as otherwise determined, 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.
Selected Annual Information 2006 2005 2004 ————————————————————————- Financial ($000s, except per share amounts) Total revenue(1) 254,938 141,634 41,025 Net earnings 6,953 12,274 3,177 Per share – basic 0.12 0.35 0.19 Per share – diluted 0.12 0.34 0.19 Funds from operations 127,440 74,550 19,773 Per share – basic 2.21 2.13 1.18 Per share – diluted 2.17 2.09 1.16 Corporate acquisitions 379,345 257,314 51,151 Capital expenditures(2) 222,214 153,606 61,133 Total assets 1,392,911 753,690 163,388 Long-term debt 138,890 – – ————————————————————————- Operating Average daily production Oil and NGLs (bbls/d) 7,554 3,984 1,578 Natural Gas (mcf/d) 25,350 13,823 6,423 Total (boe/d) 11,779 6,288 2,648 ————————————————————————- ————————————————————————- (1) Total revenue is after realized and unrealized hedging losses and gains. (2) Capital expenditures are net of property dispositions. Summary of Quarterly Results 2007 ————————————————————————- Q3 Q2 Q1 ————————————————————————- Financial ($000s, except per share amounts) Total revenue(1) 89,439 103,769 85,911 Net earnings (loss) (359,513) 1,060 (6,406) Per share – basic (5.30) 0.02 (0.09) Per share – diluted (5.30) 0.02 (0.09) Funds from operations 43,984 46,869 44,630 Per share – basic 0.65 0.69 0.66 Per share – diluted 0.65 0.68 0.66 Corporate acquisitions – – – Capital expenditures(2) 37,073 24,670 75,822 Total assets 1,044,815 1,415,081 1,421,510 Long-term debt 150,414 171,943 157,870 ————————————————————————- Operating Average daily production Oil and NGLs (bbls/d) 10,143 11,025 10,750 Natural Gas (mcf/d) 34,637 41,449 39,749 Total (boe/d) 15,916 17,933 17,375 ————————————————————————- ————————————————————————- 2006 2005 ————————————————————————- Q4 Q3 Q2 Q1 Q4 ————————————————————————- Financial ($000s, except per share amounts) Total revenue(1) 67,552 60,205 62,765 64,416 54,229 Net earnings (loss) (5,446) 514 10,594 1,291 4,855 Per share – basic (0.08) 0.01 0.20 0.03 0.11 Per share – diluted (0.08) 0.01 0.20 0.03 0.11 Funds from operations 29,973 31,171 34,750 31,546 27,957 Per share – basic 0.44 0.50 0.66 0.66 0.63 Per share – diluted 0.44 0.49 0.65 0.65 0.62 Corporate acquisitions – 289,694 – 89,651 – Capital expenditures(2) 72,711 56,144 46,590 46,769 50,861 Total assets 1,392,911 1,361,249 920,941 910,157 753,690 Long-term de