Toronto Stock Exchange: SCS
Common Shares: 84,121,297
CALGARY, April 1, 2013 /CNW/ - Second Wave Petroleum Inc. (TSX:SCS) ("Second Wave" or the "Company") announces the results of its independent year end reserves evaluation, the year end financial results as of December 31, 2012 and a general corporate update.
The audited annual financial statements, management's discussion and analysis and annual information form of the Company for the year ended December 31, 2012 have been filed on SEDAR at www.sedar.com. Information and reports regarding the Company's reserves data and other oil and gas information, as required under National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), are contained in the annual information form.
In this news release, unless otherwise stated, all reserves are expressed on a company gross basis before deduction of royalties, and all estimates of net present value are based on forecast prices and costs, before applicable taxes and discounted at 10%.
Year End 2012 Reserves and Financial Highlights:
- Increased proved plus probable ("P+P") reserves by approximately 9% year-over-year to 11,946 mboe (approximately 79% oil and natural gas liquids, or NGLs). Estimated net present value of P+P reserves at year end was $162.4 million.
- Increased P+P reserves associated with the Beaverhill Lake formation in Judy Creek by 45% to 5,989 mboe (approximately 88% oil and NGLs) with an estimated net present value of $101.8 million at year end 2012. Average gross P+P reserves per developed and undeveloped location at year end were approximately 175 mboe and 178 mboe, respectively.
- Increased the oil component of P+P reserves per undeveloped Pekisko location in Judy Creek to approximately 85 mbbl of medium grade oil per well, representing increases of 13% and 35% from 2011 and 2010 year end bookings, respectively. Average total P+P reserves per undeveloped location at year end was approximately 117 mboe (78% oil and NGLs).
- Increased production and cash flow from operating activities year-over-year by 28% to 2,162 boe/d (75% oil and NGLs) and $22.3 million, respectively.
- Increased average oil and NGL production weighting year-over-year to 75% with light oil comprising 68% of total production, up from 66% and 31%, respectively, in 2011.
- Decreased operating expense and transportation expense by 10% year-over-year to $22.65 per boe with general and administrative expenses dropping 18% year-over-year to $3.74 per boe.
2012 Year End Reserves Summary
Following is a summary of certain information contained in the Company's reserves evaluation report for the year ended December 31, 2012 prepared in accordance with NI 51-101 by InSite Petroleum Consultants Ltd., independent reserves evaluators. Further information regarding the Company's reserves data and other oil and gas information is contained in the Company's Annual Information Form for the year ended December 31, 2012, which has been filed on SEDAR at www.sedar.com.
| | | | | | |
| | | Proved
Producing | Total Proved | Total Probable | Total Proved
plus Probable |
| Oil (Mbbl) | | | | | |
| | Company Interest | 1,890 | 5,408 | 3,544 | 8,952 |
| | Net After Royalty | 1,629 | 4,730 | 3,004 | 7,734 |
| Natural Gas (MMcf) | | | | |
| | Company Interest | 4,002 | 9,016 | 5,974 | 14,990 |
| | Net After Royalty | 3,597 | 8,194 | 5,422 | 13,616 |
| Natural Gas Liquids (Mbbl) | | | | |
| | Company Interest | 131 | 297 | 199 | 496 |
| | Net After Royalty | 94 | 229 | 153 | 382 |
| Oil Equivalent (Mboe) | | | | |
| | Company Interest | 2,688 | 7,208 | 4,738 | 11,946 |
| | Net After Royalty | 2,323 | 6,324 | 4,061 | 10,385 |
| | | | | | |
| | | | | | |
| | | | | | |
| Before Tax Present Value ($000) - Company Interest | | |
| Discounted at | | | | |
| | 0% | $92,175 | $191,836 | $134,131 | $325,967 |
| | 5% | $77,818 | $141,829 | $83,198 | $225,027 |
| | 10% | $67,528 | $108,597 | $53,789 | $162,385 |
| | 15% | $59,868 | $85,561 | $35,840 | $121,401 |
| | | | | | |
| Notes: |
| (1) | As used in the preceding table, "company interest" refers to the Company's gross reserves, being the Company's working
interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the
Company. |
| (2) | As used in the preceding table, "net after royalty" refers to the Company's working interest (operating or non-operating)
share after deduction of royalty obligations, plus the Company's royalty interests in reserves. |
| | |
2012 Year End Reserves Analysis
Total P+P reserves increased year-over-year by approximately 9% to 11,946 mboe from 10,951 mboe at year end 2011, with an oil and NGL weighting of 79% and a net present value of $162.4 million. Net capital spending for the year totaled $59.8 million, including $8.5 million on facilities and infrastructure projects to facilitate current and future volumes from its Beaverhill Lake and Pekisko developments. Annualized corporate production in 2012 was 790 mboe (2,162 boe/d). Estimated future development capital (discounted at 10%) associated with the P+P reserves increased year-over-year to $158.6 million from $138.8 million at year end 2011.
The overall year-over-year reduction in net present value of P+P reserves from approximately $192.9 million at year end 2011 to approximately $162.4 million at year end 2012, is primarily attributable to: a reduction in near-term commodity price forecasts; the disposition of approximately 363 mboe of low netback natural gas in a non-core area for total proceeds of $1.5 million during 2012; a negative revision of approximately 100 mbbl on the Company's Battle Creek heavy oil CO2 flood project in southwest Saskatchewan due to reduced economics related to lower heavy oil price forecasts; and higher future development capital estimates per production unit associated with the Beaverhill Lake development, as more particularly described below.
During 2012, the Company spent $55.2 million focused on delineating the Beaverhill Lake formation on its Judy Creek land base through the drilling of 17 gross (8.0 net) horizontal light oil wells. At year end 2012 the Company had a total of 35 gross (15.8 net) producing Beaverhill Lake wells booked, with average gross P+P producing reserves per well of 175 mboe (83% oil and NGLs), over a Beaverhill Lake development footprint spanning an area of approximately 48 square kilometers (30 square miles) for an average of 1.3 producing wells per square mile. The Company booked an additional 58 gross (23.8 net) undeveloped Beaverhill Lake locations at year end with an average gross P+P reserve volume of 178 mboe (87% oil and NGLs) resulting in an average expected future well density of 3.1 wells per section over the current core development land block. Estimated future development capital per undeveloped location (inflated at 2%) dropped year-over-year to $5.00 million at year end 2012 from $5.25 million at year end 2011 primarily as a result of improvements in completion and production testing techniques. At year end each of the 58 gross undeveloped locations had a P+P net present value of approximately $2.0 million on estimated average future development capital of $5.0 million (inflated at 2%) per well, representing an average rate of return on primary production of 35%.
Year-over-year average P+P reserves per well in the Judy Creek Beaverhill Lake play decreased from approximately 190 mboe at year end 2011 to current bookings of approximately 177 mboe. The Company reduced its average reserves expectations primarily due to higher than anticipated declines on its existing producing wells and a larger percentage of its year end drilling inventory being located on the southeast side of its land base, which has historically been less productive than the remainder of the Company's development lands. The decrease in reserves associated with higher than anticipated declines on previously booked wells resulted in an aggregate negative technical revision of approximately 229 mbbl at year end 2012, which was offset by drilling additions of 2,025 mbbl. Based on internal estimates of original oil in place in the Beaverhill Lake formation, the Company estimates that its current P+P reserves bookings represent an 11% recovery factor over its core development area.
Through its delineation drilling program in 2011 and 2012 the Company has been able to establish the economic productivity of a substantial amount of its Judy Creek land base in the Beaverhill Lake formation, resulting in a 5-to-7 year inventory of lower risk development drilling. The Company built three distinct Beaverhill Lake light oil batteries at Judy Creek in 2012, which have been designed and positioned to facilitate the eventual consolidation of the Company's Beaverhill Lake production in Judy Creek and the potential implementation of future water flood projects in the Beaverhill Lake formation. The Company's activities in 2012 were oriented towards laying the groundwork for a full developmental drilling program of up to four wells per section with potential secondary recovery via water flood. Public data from off-setting pools in the Beaverhill Lake formation have seen recovery factors exceed 30% under secondary recovery, although there can be no assurance that similar results can be realized on Company lands.
As of year end 2012 the Company had booked approximately 5,986 mboe of P+P reserves in the Beaverhill Lake formation with a net present value of approximately $101.8 million and approximately $97.4 million (10% discount) of associated future development capital. To year end 2012 the Company has spent approximately $85 million of net capital on the Beaverhill Lake formation in its core Judy Creek area and has produced approximately 689 mboe with net operating cash flow of approximately $39.1 million ($56.75 per boe operating netback based on total production to year end 2012), resulting in current full cycle finding and development costs on primary production of approximately $27.30 per boe or a 2.1 recycle ratio based on P+P reserves and historical operating netbacks. The Company believes that secondary recovery has the potential to further improve the full cycle economics of the play.
In 2012, the amount of capital directed to its 100% working interest Pekisko medium grade oil play in Judy Creek was not significant. However the Company advanced its ongoing water flood pilot project and also drilled its first dual leg horizontal oil well in the Pekisko formation. The first positive production response to the pilot water flood was experienced in the third quarter of 2012, with monthly production rates on the three Pekisko oil wells within the pilot project area (16-32-063-09W5, 12-31-063-09W5 and 05-31-063-09W5) increasing on average 100% from the first half of 2012 to December 2012. The pilot water flood results to date have met the Company expectations however additional production history will be needed to properly assess the full economic value of the water flood in the Company's Pekisko reservoir.
In addition to the ongoing water flood pilot, the Company drilled and completed its first dual leg horizontal well in the Judy Creek Pekisko reservoir at the 04-19-063-09W5 (04-19) location late in the fourth quarter of 2012. Although a down hole tool failure resulted in the Company being able to stimulate only one of the two horizontal legs the 04-19 well tested at rates of approximately 50 bbl/d of medium grade oil and 240 mcf/d of natural gas for an aggregate test rate of 90 boe/d over the first 30 producing days. Taking into account the incomplete stimulation the tested production rate represents a significant improvement to past rates achieved on the play. The Company believes that that this new drilling and completion technique represents a significant economic improvement to completion and drilling methodologies previously used.
Based on results from its 04-19 drill and the Company's ongoing water flood pilots, the amount of oil component of P+P reserves per undeveloped location booked at year end 2012 increased to an average of approximately 85 mbbl of medium grade oil per well, representing increases of approximately 13% and 35% from year end 2011 and 2010, respectively. Average total P+P reserves per undeveloped location remained relatively static year-over-year at 117 mboe at year end 2012 versus 121 mboe at year end 2011 but oil and NGL weighting increased year-over-year to 78% from 64%. Estimated future development capital per undeveloped location (inflated at 2%) declined to $2.10 million at year end 2012 from $2.25 million at year end 2011 based primarily on results from the 04-19 well. The Company increased well density and expected recovery factors year-over-year to a maximum of 8 wells per section at year end 2012 from 4 wells per section at year end 2011 representing an average estimated recovery factor of 4.5% per developed section based on estimates provided by its external reserve evaluators. The reduction in its undeveloped locations in the Pekisko formation at year end 2012 was off-set by an increase in undeveloped locations booked in the Beaverhill Lake formation. As a result undeveloped locations in the Pekisko formation dropped from 34 wells at year end 2011 to 27 wells at year end 2012 with future development capital dropping from $64.4 million to $49.7 million (discounted at 10%), respectively.
At year end 2012 the Company had a total of 22 gross (22.0 net) producing horizontal Pekisko oil wells with an average reserves booking of 96 mboe (60% oil and NGLs) per well. A total of 27 gross (27.0 net) undeveloped locations were booked at year end using the new dual leg technology with an average reserves booking of 117 mboe (78% oil and NGLs) per well. Future development capital per well of $2.1 million (inflated at 2%) was estimated at year end with each undeveloped location having an average P+P net present value of $950,000, representing a 33% rate of return on primary production.
In addition to its initial production test from the 04-19 well the Company concurrently initiated water injection in the Pekisko formation at the 02-24-063-10W5 well located approximately 150 meters south of the 04-19 well to create its first close proximity water flood pilot in Judy Creek. Previous pilot spacing between horizontal water injector and horizontal oil producer was approximately 600 meters. Although still in its infancy the near proximity water flood pilot at 04-19 will provide valuable information to help the Company optimize its full cycle development plan for the Judy Creek Pekisko pool. The Company's Pekisko development footprint as booked within its year end 2012 reserves represents approximately 6.2 total sections of development at 8 wells per section, or approximately 8% of the total Judy Creek Pekisko oil pool as internally mapped by Second Wave.
At year end 2012 the Company had estimated P+P reserves with a net present value of $162.4 million and 125,700 net undeveloped acres of land. Using an undeveloped land value of $150 per acre the Company estimates its undeveloped land to have a value of $18.9 million. At year end 2012 the Company had approximately 84.1 million shares outstanding and $114.4 million in net debt, resulting in an estimated net asset value per share of $0.80 (before tax, discounted at 10%) when the undeveloped land value of $18.9 million is included.
Financial Summary
Selected Financial Information
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| | | | | | | | | | | | | |
| ($000s, except per share and per boe amounts) | Three months ended
December 31, | Year ended
December 31, |
| | 2012 | | 2011 | | % ? | | 2012 | | 2011 | | % ? | |
| Sales volumes | | | | | | | | | | | | |
| | Oil (bbl/d) | 1,061 | | 1,570 | | (32) | | 1,506 | | 1,006 | | 50 | |
| | Natural gas liquids (bbl/d) | 126 | | 94 | | 34 | | 113 | | 104 | | 9 | |
| | Natural gas (mcf/d) | 3,759 | | 3,142 | | 20 | | 3,260 | | 3,445 | | (5) | |
| Combined boe/d (6:1) | 1,813 | | 2,188 | | (17) | | 2,162 | | 1,684 | | 28 | |
| | | | | | | | | | | | | |
| Crude oil and liquids weighting (%) | 65 | | 62 | | 5 | | 75 | | 66 | | 14 | |
| Per boe | | | | | | | | | | | | |
| | Petroleum and natural gas sales | 55.78 | | 76.33 | | (27) | | 61.93 | | 62.80 | | (1) | |
| | Royalties | (8.29) | | (3.54) | | 134 | | (4.86) | | (4.04) | | 20 | |
| | Lease operating costs | (21.69) | | (22.99) | | (6) | | (21.29) | | (23.40) | | (9) | |
| | Transportation | (0.39) | | (0.38) | | 3 | | (1.36) | | (1.82) | | (25) | |
| Operating netback(1) | 25.41 | | 49.42 | | (49) | | 34.42 | | 33.54 | | 3 | |
| | | | | | | | | | | | | |
| Net capital expenditures(2) | 3,455 | | 16,604 | | (79) | | 59,840 | | 47,282 | | 27 | |
| | | | | | | | | | | | | |
| Cash from operating activities | 5,663 | | 5,537 | | 2 | | 32,338 | | 13,304 | | 143 | |
| Cash from operating activities per share (1) | 0.07 | | 0.07 | | - | | 0.39 | | 0.16 | | 144 | |
| | | | | | | | | | | | | |
| Net loss | (14,816) | | (8,734) | | 70 | | (15,165) | | (8,595) | | 76 | |
| Net loss per share | (0.18) | | (0.11) | | 64 | | (0.18) | | (0.10) | | 80 | |
| | | | | | | | | | | | | |
| (1) | Cash from operating activities per share and operating netback are not recognized measures under IFRS and are therefore unlikely to be
comparable to similar measures presented by other oil and gas companies. Management considers them to be important measures as they
demonstrate the Company's ability to generate the cash flow necessary to fund future growth through capital investment. |
| (2) | Includes expenditures on Exploration and Evaluation activities. |
Fourth Quarter and Annual Financial Results Analysis
Annual production levels in 2012 increased 28% year-over-year to 2,162 boe/d (75% oil and NGLs) from 1,684 boe/d (66% oil and NGLs) in 2011 as a result of increased production levels in the Company's Judy Creek Beaverhill Lake light oil play. The Company's production in 2012 remained focused on Judy Creek with 93% of its production derived from this field. On a quarterly basis production in the fourth quarter was down 17% year-over-year to 1,813 boe/d (65% oil and NGL weighting).
Fourth quarter production in 2012 was negatively impacted by curtailments of the Company's Beaverhill Lake production due to maximum rate limitations of 64 boe/d net for the quarter with an additional 120 boe/d of lost Pekisko and Beaverhill Lake production related to a gas plant shut down and a pipeline break in Judy Creek. In addition, the Company significantly reduced its capital activities in the second half of 2012 and as such the declines in its production on a quarter-over-quarter and year-over-year basis can also be attributed to natural declines in its Beaverhill Lake production in Judy Creek. Fourth quarter Beaverhill Lake production totaled 1,140 boe/d representing a 42% drop from second quarter peak levels of 1,916 boe/d and a 19% drop from the average annual production level of 1,406 boe/d. The Company drilled 17 gross (8.0 net) Beaverhill Lake wells during the year however all of the wells were spud during the first half of the year and as such peak production coincided with the higher level of capital investment experienced during the first half of 2012. As the Company's Beaverhill Lake wells have now produced for an average of 440 days (as of April 1, 2013) it expects that further declines associated with this production base will be substantially more moderate than the declines experienced to date.
Realized pricing in the fourth quarter and annually dropped 27% and 1%, respectively from 2011 levels to $55.78 per boe. Operating and transportation costs on a year-over-year and quarter-over-quarter basis dropped 11% and 5%, respectively, to $22.65 per boe and $22.08, respectively, as a result of the consolidation of the Company's production in its Judy Creek core area and the implementation of various operating cost saving initiatives. Royalty rates on a per unit basis increased year-over-year by 124% to $8.29 per boe as the Company had 6 gross (2.4 net) Beaverhill Lake light oil wells fully utilize their 5% crown royalty holiday and revert back to normal crown royalties after producing in excess of 90 mboe in the first 24 months of production.
Operating netbacks remained relatively static increasing 3% year-over-year to $34.42 per boe in 2012. Exiting the fourth quarter the liquids weighting of the Company's production has returned to historical levels at approximately 75%. The Company continues to remain bullish on the potential to realize improved netbacks as future commodity prices strengthen and Second Wave continues improving its cost structure in Judy Creek while advancing both its Beaverhill Lake and Pekisko developments.
Cash flow from operating activities in 2012 increased by 28% year-over-year as a result of a 28% increase in 2012 production levels as costs and product pricing remained static over these time periods.
Outlook
The past fifteen months have been challenging for the Canadian junior oil and gas sector as commodity prices shifted lower, oil differentials related to Canadian crude oil widened considerably and liquidity in the capital markets reduced significantly. The Company entered 2012 with its shares trading at a significant premium to its year end 2011 net asset value and exited 2012 trading at a significant discount to its net asset value.
Despite these challenges, the Company has built a significant land base in its Judy Creek core area with two distinct oil resource plays in the Beaverhill Lake and Pekisko Formations. Through significant capital investment Second Wave has brought both plays from an exploration stand point to the cusp of full development. The Company had previously relied on cash flow, debt and equity financings to fund its capital activities with capital budgets exceeding cash flow in each of 2010, 2011 and 2012.
Corporate debt levels have increased moderately since the end of the first quarter of 2012 to December 31, 2012. Weaker commodity prices coupled with the Company's production being reduced considerably over this time period have resulted in the Company's current net debt of $114 million being unsustainable at approximately five times its annualized cash flow.
Second Wave exited its strategic alternatives review process in the second quarter of 2012. Pursuant to that process the Company carefully reviewed, with the assistance of its financial advisor, certain business alternatives with a view to adding shareholder value and improving its financial position. Second Wave was not successful in finding a suitable solution for its shareholders at that time or subsequent to its conclusion.
The Company is currently in the process of setting a 2013 capital budget while concurrently reviewing its credit facilities with its commercial lenders. Based on lender discussions to date the Company anticipates that its current bank line of $90 million will be significantly reduced and, based on the current business environment and the Company's current cash flow generating capabilities, that a $55 to $60 million dollar line would be more appropriate. Second Wave's board of directors (the "Board") continues to review financing alternatives to address the borrowing base shortfall and working capital deficiency while leaving the Company sufficient financial flexibility. Such alternatives may include asset dispositions, rights offering, long term debt or equity financings. The Board expects to determine the appropriate alternative and finalize a 2013 capital budget early in the second quarter.