BNK Petroleum Inc. Announces 3rd Quarter 2013 results
Alberta (ots/PRNewswire)
All amounts are in U.S. Dollars unless otherwise indicated:
Third Quarter Nine Months
2013 2012 % 2013 2012 %
Earnings (Loss):
$ Thousands $(2,445) $(4,260) - $(8,694) $(10,410) -
$ per common share $ (0.02) $(0.03) - $(0.06) $(0.07) -
assuming dilution
Capital Expenditures $34,908 $12,691 175% $45,270 $35,592 27%
Average Production (Boepd) 302 1,547 (80%) 743 1,547 (52%)
Average Product Price per Barrel $72.81 $34.11 113% $40.97 $35.01 17%
Average Netback per Barrel $50.13 $17.77 182% $22.87 $17.71 29%
9/30/2013 12/31/2012 9/30/2012
Cash, Cash Equivalents and
Marketable Securities $73,392 $2,836 $9,549
Working Capital $54,069 $472 $7,081
BNK's President and Chief Executive Officer, Wolf Regener commented:
"At the end of the quarter, we completed the Hartgraves 5-3H well which is our most successful Caney well so far. The Hartgraves 5-3H well was the third well in our 2013 drilling program and was fracture stimulated in September. The fracture stimulation was designed utilizing lessons learned from previous stimulations and included the use of all ceramic proppant and had tighter fracture stimulation stage spacings, among other modifications. Subsequent to the end of the quarter, the well achieved a 30 day initial production (IP) rate of 748 barrels of oil equivalent per day (BOEPD) of which 388 barrels was oil. We believe that the improved production that the Company is achieving in each successive Caney well is the result of continuous improvements in completion design as geologically no significant variations have been observed. We expect the design used in the Hartgraves 5-3H well to also reduce the initial production decline and increase overall recoveries by accessing a much larger part of the reservoir near the lateral.
The second well in our 2013 drilling program, the Dunn 2-2H, was completed earlier in the third quarter with 15 stages successfully fracture stimulated. The fracture stimulation design for the Dunn 2-2H well was improved based on the previous Caney well, the Barnes 6-3H, and utilized both sand and ceramic proppant. The Dunn 2-2H well realized peak initial production rates as high as 620 BOEPD with 300 barrels of oil and had a 30 day IP rate of 420 BOEPD of which 195 barrels were oil. The first well in the 2013 drilling program, the Barnes 6-3H well, had a 30 day IP rate of 200 BOEPD of which 93 barrels were oil.
In April of this year we closed the sale of virtually all of our producing assets. Less than five months later, our average third quarter production, which does not include production from the Hartgraves 5-3H well, rose to 302 BOEPD or approximately 20% of our average 2012 third quarter production. In addition, our netbacks for this Caney production averaged $50.13 per barrel for the third quarter of 2013, a 182% increase over the netbacks from the Woodford production in the third quarter of last year, which averaged $17.77 per barrel.
We are now moving forward with our fourth well in the 2013 Caney drilling program, the Barnes 7-2H, which was spud on August 31. The Barnes 7-2H well was initially drilled vertically so that we could collect whole core and run a full suite of open hole logs over the Caney, T-zone and Upper Sycamore formations. Analysis of the more detailed data collected from the vertical well helped us optimize the placing of the subsequently drilled horizontal leg in what appears to be a more prolific subinterval of the Caney. We have since begun fracture stimulation operations, to date completing 15% of the planned stimulations, and expect to have flowback results in mid to late November. The fracture design is a modified version of what was done in the Hartgraves 5-3H well. We also began drilling the Wiggins 12-8H well in October and expect to complete the fracture stimulation of that well in December.
In Poland, the Company has filed a concession modification amendment for its Bytow concession and is awaiting its approval, after having received the approved Environmental Impact Assessment for the concession. The final drilling permit for the re-entry of the Gapowo B-1 well will be submitted after the concession amendment is approved. Once all permits are received, we intend to finalize a drilling contract and mobilize a drilling rig to re-enter the Gapowo B-1 well and drill a horizontal lateral in the Ordovician formation.
The Company incurred a $2.4 million loss in the quarter versus a loss of $4.3 million in the third quarter of 2012. Production decreased 80% in the comparative quarters due to the April 2013 sale of the Company's Tishomingo field assets, excluding the Caney and Upper Sycamore formations (the "Woodford Sale"), which was offset by production from our subsequently drilled Caney wells, while average pricing per barrel increased 113% due to the Caney production having a much higher percentage of oil vs gas and natural gas liquids (NGLs) than the Woodford production. Oil and gas revenues net of royalties declined by $2.3 million mainly due to the Woodford Sale. At September 30, 2013, cash and marketable securities on hand were over $73 million, some of which the Company will use to continue our 2013 drilling program in the Caney and to move our European projects forward once permits are approved.
Through the first nine months of 2013 the Company incurred a loss of $8.7 million versus a loss of $10.4 million through the first nine months of 2012. Oil and gas revenues declined $5.3 million, or 44%, due to a decrease in average production per day due to the Woodford Sale which was offset by production from our subsequently drilled Caney wells and an increase in average pricing per barrel.
The Company recorded a gain of $9.6 million on the Woodford Sale, and used a portion of the proceeds to pay down its debt from $41 million to $100,000. Offsetting this gain was $3.5 million related to the amortization of deferred financing costs, a pre-payment penalty of $2.5 million and a $2.5 million payment to settle all of our financial commodity contracts."
THIRD QUARTER HIGHLIGHTS:
- Drilled and fracture stimulated the Dunn 2-2H and Hartgraves 5-3H wells in the Caney formation in the Tishomingo Field - In August, commenced drilling of the fourth Caney well in the 2013 drilling program, the Barnes 7-2H well, which is expected to start flowing back in November - At quarter end, cash and marketable securities totaled $73.4 million and working capital was $54.0 million - Production started increasing, post Woodford Sale, and averaged 302 BOEPD in the quarter - Oil and gas revenues started increasing post Woodford Sale, and totaled $1.6 million for the quarter - Loss of $2.4 million versus loss of $4.3 million in the third quarter of 2012 - G&A decreased by $0.7 million due to reductions in staff and lower costs in Europe
Third Quarter 2013 to Third Quarter 2012
Oil and gas revenues net of royalties totaled $1,647,000 in the quarter versus $3,946,000 in the third quarter of 2012. Oil revenues were $1,705,000 in the quarter versus $2,170,000 in the third quarter of 2012, a decline of 21% as production decreased 32% to an average of 177 barrels per day due to the Woodford Sale while average oil prices increased 17% or $14.95 a barrel. Natural gas revenues declined $801,000 or 89% as natural gas production decreased to 329 mcfd due to the Woodford Sale while average natural gas prices per mcf increased 30%. NGL revenue declined $1,566,000 or 88% to $217,000 as average production decreased 89% to 70 boepd as a result of the Woodford Sale while average NGL prices increased 13% to $33.84 a barrel.
Other income increased $161,000 to $442,000 as third quarter 2013 results included higher management fee revenue relating to the Company's joint venture in Saponis Investments Sp. zo.o and gains from equipment sales.
Exploration and evaluation expenses declined $49,000 between quarters due to less E&E activity in new areas of interest.
Production and operating expenses declined $1,163,000 between quarters due to the Woodford Sale.
Depletion and depreciation expense decreased $1,020,000 between quarters due to decreased production and depletion base and lower production as a result of the Woodford Sale.
General and administrative expenses decreased $711,000 between quarters primarily due to lower payroll and related costs and lower professional fees incurred in Europe relating to legal, accounting, and management fees which were partially offset by higher director fees incurred in 2013. In addition, the third quarter of 2013 included approximately $300,000 of non-recurring charges.
Stock based compensation decreased $70,000 between quarters due to lower stock option valuations and awards becoming fully vested.
Finance income decreased $424,000 due to realized gains on financial commodity contracts in 2012. Finance expense decreased $1,684,000 primarily due to a $1,091,000 unrealized loss on financial commodity contracts in 2012 and interest on loans and borrowings of $385,000 in 2012.
Capital expenditures of $34,908,000 were incurred in the third quarter of 2013, almost all of which was spent in Oklahoma.
FIRST NINE MONTHS 2013 VERSUS FIRST NINE MONTHS 2012 HIGHLIGHTS
- Drilled and fracture stimulated the first three wells of the Company's 2013 drilling program in the Caney formation in the Tishomingo field - Closed the Woodford Sale in April 2013 for $147.1 million (which includes $560,000 of net operating profit for the first 18 days of April 2013) - Paid down the Company's credit facility from $41 million to $100,000 in connection with the Woodford Sale - Settled all the financial derivative contracts in April 2013 in connection with the Woodford Sale and incurred a realized loss of $2.5 million - Capital expenditures increased $9.7 million or 27% to $45.3 million primarily due to the 2013 drilling program in Oklahoma which totaled $43.7 million for the first nine months of 2013. The 2012 capital expenditures amount included $26 million of capital expenditures incurred in Poland - G&A expenses decreased by $2.0 million primarily due to staff reductions and lower costs in Europe - Average production decreased 52% between comparative first nine month periods due to the Woodford Sale, which was partially offset by production from subsequently drilled Caney wells - A net loss of $8.7 million was incurred in the first nine months of 2013 versus a loss of $10.4 million in the same period in 2012
First Nine Months 2013 to First Nine Months 2012
Oil and natural gas revenues net of royalties declined $5,303,000 or 44% to $6,758,000. Oil revenues before royalties decreased $2,270,000 to $4,433,000 due to a 35% decrease in production due to the Woodford Sale while prices increased 2% between periods. Natural gas revenues before royalties declined $1,078,000 or 42% due to a 56% decline in average production due to the Woodford Sale partially offset by a 33% increase in natural gas prices per mcf. NGL revenue before royalties declined $3,183,000 or 57% to $2,364,000 due to a 55% decline in average production per day due to the Woodford Sale and a 5% decline in average NGL prices.
Other income increased due to higher management fee revenue relating to the joint venture in Saponis Investments Sp. zo.o and gains from equipment sales.
Exploration and evaluation expenses declined $253,000 primarily due to less E&E activity in new areas of interest.
Production and operating expenses decreased 54% as production decreased 52% due to the Woodford Sale.
Depletion and depreciation expense decreased $2,099,000 primarily due to decreased production and depletion base and lower production as a result of the Woodford Sale.
General and administrative expenses decreased $1,981,000 primarily due to lower payroll and related costs, lower professional fees incurred in Europe relating to legal, accounting, management fees and lower travel costs partially offset by higher director fees in 2013.
Finance Income decreased $1,137,000 due to realized gains on financial commodity contracts and
unrealized gains on warrant revaluation in 2012. Finance expense increased $8,419,000 primarily due to a $7,520,000 charge related to interest on loans and borrowings which included $3.5 million for the amortization of deferred financings costs and $2.5 million of pre-payment penalties related to the loan paydown along with a realized loss on financial commodity contracts of $2.5 million as these contracts were all settled in April 2013.
Cash and marketable securities have increased by $70,556,000 through the first nine months of 2013 primarily due to the Woodford Sale offset by the 2013 capital expenditures.
BNK PETROLEUM INC.
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Unaudited, Expressed in Thousands of United States Dollars)
September 30, December 31,
2013 2012
Current assets
Cash and cash
equivalents $ 43,359 $ 2,836
Investments in
marketable
securities 30,033 -
Trade and other
receivables 5,472 11,363
Deposits and
prepaid expenses 4,512 2,334
Fair value of
commodity
contracts - 779
83,376 17,312
Non-current assets
Long-term
receivables 725 1,297
Investments in
joint ventures 10,226 10,114
Property, plant
and equipment 61,530 156,549
Exploration and
evaluation assets 35,151 33,590
107,632 201,550
Total assets $ 191,008 $ 218,862
Current liabilities
Trade and other
payables $ 29,307 $ 16,840
Loans and
borrowings - 31,797
29,307 48,637
Non-current liabilities
Loans and
borrowings 100 -
Fair value of
commodity
contracts - 75
Asset retirement
obligations 271 1,312
Warrants 1 3
372 1,390
Equity
Share capital 247,485 247,326
Contributed
surplus 17,692 16,663
Deficit (103,848) (95,154)
Total equity 161,329 168,835
Total equity and liabilities $ 191,008 $ 218,862
BNK PETROLEUM, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE LOSS
(Unaudited, expressed in Thousands of United States dollars,
except per share amounts)
Three months ended Nine months ended
September 30 September 30
2013 2012 2013 2012
Revenue:
Oil and natural gas
revenue, net $ 1,647 $ 3,946 $ 6,758 $ 12,061
Gathering income - 330 331 1,064
Gain on sale of assets (129) - 9,618 -
Management fees and other
income 442 281 961 735
1,960 4,557 17,668 13,860
Expenses:
Exploration and
evaluation - 49 57 310
Production and operating 251 1,414 2,113 4,549
Depletion and
depreciation 720 1,740 3,057 5,156
General and
administrative 3,223 3,934 9,930 11,911
Share based compensation 140 210 589 685
Loss from investments in
joint ventures 29 33 94 273
Restructuring expenses - 135 595 1,015
4,363 7,515 16,435 23,899
Finance income 66 490 108 1,245
Finance expense 108 1,792 10,035 1,616
Net loss and
comprehensive loss $ (2,445) $ (4,260) $ (8,694) $ (10,410)
Net loss per share
Basic and
Diluted $ (0.02) $ (0.03) $ (0.06) $ (0.07)
BNK PETROLEUM, INC.
THIRD QUARTER 2013
(Unaudited, expressed in Thousands of United States dollars, except as noted)
3rd Quarter First Nine Months
2013 2012 2013 2012
Oil revenue before royalties $1,705 2,170 4,433 6,703
Gas revenue before royalties 101 902 1,514 2,592
NGL revenue before royalties 217 1,783 2,364 5,547
Oil and Gas revenue 2,023 4,855 8,311 14,842
Cash flow used by operating activities (248) (2053) (8,942) (10,937)
Additions to property, plant & equipment (34,789) (5,365) (43,882) (8,933)
Additions to Exploration and Evaluation Assets (119) (7,326) (1,388) (26,659)
Statistics:
First Nine
3rd Quarter Months
2013 2012 2013 2012
Average natural gas production (mcf/d) 329 3,816 1,714 3,894
Average NGL production (Boepd) 70 649 287 637
Average Oil production (Bopd) 177 262 170 261
Average production (Boepd) 302 1,547 743 1,547
Average natural gas price ($/mcf) $3.33 $2.57 $3.24 $2.43
Average NGL price ($/bbl) $33.84 $29.85 $30.22 $31.80
Average oil price ($/bbl) $104.98 $90.03 $95.71 $93.63
Average price per barrel $72.81 $34.11 $40.97 $35.01
Royalties per barrel 13.65 6.40 7.68 6.57
Operating expenses per barrel 9.03 9.94 10.42 10.73
Netback per barrel $50.13 $17.77 $22.87 $17.71
The information outlined above is extracted from and should be read in conjunction with the Company's unaudited financial statements for the nine months ended September 30, 2013 and the related management's discussion and analysis thereof, copies of which are available under the Company's profile at http://www.sedar.com.
Non-IFRS Information
Netback per barrel and its components are calculated by dividing revenue less royalties and operating expenses by the Company's sales volume during the period. Netback per barrel is a non-IFRS measure but it is commonly used by oil and gas companies to illustrate the unit contribution of each barrel produced. This is a useful measure for investors to compare the performance of one entity with another. However, non-IFRS measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies.
The Company's natural gas production is reported in thousand cubic feet or (mcf). The Company also uses "barrels" (bbls) or "barrels of oil equivalent" (boe or BOE) in this report to reflect natural gas liquids and oil production and sales. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Caution Regarding Forward-Looking Information
Statements contained in this news release constitute "forward-looking information" as such term is used in applicable Canadian securities laws, including information regarding the proposed timing and expected results of exploratory and development work including production from the Lower Caney and upper Sycamore formations on the Company's Oklahoma acreage, the effect of design and performance improvements on future productivity, the anticipated timing of commencement and completion of drilling and fracture-stimulations in connection with the Company's Caney drilling program, the advancement of the Company's European projects, including permit and concession applications and approvals and drilling plans and the planned use and sufficiency of cash and marketable securities on hand. Forward-looking information is based on plans and estimates of management at the date the information is provided and certain factors and assumptions of management, including that the Company's geologic models will be validated, that indications of early results are reasonably accurate predictors of the prospectiveness of the shale intervals, that previous exploration results are indicative of future results and success, that expected production from future wells can be achieved as modeled, declines will match the modeling, future well production rates will be improved over existing wells, that rates of return as modeled can be achieved, that recoveries are consistent with management's expectations, that additional wells are actually drilled and completed, that design and performance improvements will reduce development time and expense and improve productivity, that discoveries will prove to be economic, that anticipated results and estimated costs will be consistent with managements' expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the Company will continue to be able to access sufficient capital through financings, credit facilities farm-ins or other participation arrangements to maintain its projects, that the Company will not be adversely affected by changing government policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates and that global economic conditions will not deteriorate in a manner that has an adverse impact on the Company's business and its ability to advance its business strategy. Forward looking information is subject to a variety of risks and uncertainties and other factors that could cause plans, estimates, timing and actual results to vary materially from those projected in such forward-looking information. Factors that could cause the forward-looking information in this news release to change or to be inaccurate include, but are not limited to, the risk that any of the assumptions on which such forward looking information is based vary or prove to be invalid, including that anticipated results and estimated costs will not be consistent with managements' expectations, the Company or its subsidiaries is not able for any reason to obtain and provide the information necessary to secure required approvals or that required regulatory approvals are otherwise not available when required and on terms acceptable to the Company, that unexpected geological results are encountered, that completion techniques require further optimization, that production rates do not match the Company's assumptions, that very low or no production rates are achieved, that the Company is unable to access required capital, that the Company is adversely affected by changing g overnment policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates, that occurrences such as those that are assumed will not occur, do in fact occur, and those conditions that are assumed will continue or improve, do not continue or improve, political and currency risks and the other risks and uncertainties applicable to exploration and development activities and the Company's business, including those set forth in the Company's management's discussion and analysis and annual information form filed under the Company's profile on http://www.sedar.com. Although the Company has attempted to take into account important factors that could cause actual results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. Accordingly, readers should not place undue reliance on forward-looking information. The Company undertakes no obligation to update these forward-looking statements, other than as required by applicable law.
About BNK Petroleum Inc.
BNK Petroleum Inc. is an international oil and gas exploration and production company focused on finding and exploiting large, predominately unconventional oil and gas resource plays. Through various affiliates and subsidiaries, the Company owns and operates shale gas properties and concessions in the United States, Poland, Germany and Spain. Additionally the Company is utilizing its technical and operational expertise to identify and acquire additional unconventional projects. The Company's shares are traded on the Toronto Stock Exchange under the stock symbol BKX.
For further information:
Wolf E. Regener, President and Chief Executive Officer +1 (805) 484-3613 Email: investorrelations@bnkpetroleum.com Website: http://www.bnkpetroleum.com
(BKX.)