Manitok Energy Inc. (the “Corporation” or “Manitok“) (TSX VENTURE:MEI) announces its financial and operating results for the third quarter of 2013.
The full text of Manitok’s third quarter report containing its unaudited condensed interim financial statements as at and for the three and nine months ended September 30, 2013 and the related management’s discussion and analysis will be available electronically on Manitok’s profile on the System for Electronic Document Analysis and Retrieval (“SEDAR“) at www.sedar.com and also on Manitok’s website atwww.manitokenergy.com. All dollar figures are in Canadian dollars unless otherwise noted.
Third Quarter 2013 Operational & Financial Highlights:
- An increase in average production by 51% to 3,819 boe/d for the third quarter of 2013 from 2,525 boe/d for the comparable period in 2012. As at September 30, 2013, approximately 5,800 additional net barrels of oil (63 bbls/d) as compared to the second quarter of 2013, were held in inventory and not included in third quarter production, due to pipeline and terminal restrictions. The inventoried barrels were sold in October 2013.
- Funds from operations increased by 18% to $8.3 million ($0.12 per share) in the third quarter of 2013 from $7.0 million ($0.11 per share) for the third quarter of 2012.
- Operating netback before the realized gain or loss of financial instruments increased by 2% to $32.57 per boe for the third quarter of 2013 from $32.04 per boe for the comparable period in 2012.
- Production per weighted average diluted share increased 33% from the third quarter of 2012.
- Total operating costs in the third quarter of 2013 were $5.90 per boe net of recoveries and $7.17 per boe prior to recoveries, which is 19% and 22% lower, respectively, on a boe basis, than the comparable period last year. Transportation and marketing costs were $2.56 per boe, down from $2.62 per boe in the comparable period last year.
- Capital expenditures for the third quarter of 2013 were $17.5 million, which is up 8% from $16.2 million in the comparable quarter in 2013.
- Drilled 4 gross (2.6 net) wells in the third quarter of 2013, 3 gross (1.8 net) Cardium light oil wells and 1 gross (0.8 net) Ostracod liquids rich natural gas well.
- As at September 30, 2013, net debt was approximately $21.4 million and unused credit facilities were about $85.4 million.
- An 8% increase in undeveloped land to 222,181 net acres as at September 30, 2013 as compared to 206,383 net acres as at June 30, 2013
- Purchased 1,087,100 shares at an average price of $2.65 in the quarter pursuant to its normal course issuer bid (“NCIB“).
Operational and Financial Highlights |
(Unaudited) |
Three months ended September 30, | Nine months ended September 30, | ||||||||
2013 | 2012 | 2013 | 2012 | ||||||
Operating | |||||||||
Average daily production | |||||||||
Natural gas (mcf/d) | 11,735 | 7,706 | 11,415 | 8,626 | |||||
Light oil (bbls/d) | 1,781 | 1,171 | 1,833 | 516 | |||||
Heavy oil (bbls/d) | – | – | – | 125 | |||||
NGLs (bbls/d) | 82 | 70 | 82 | 78 | |||||
Total (boe/d) | 3,819 | 2,525 | 3,818 | 2,156 | |||||
Average realized sales price (CAD$) | |||||||||
Natural gas ($/mcf) | 2.73 | 2.52 | 3.45 | 2.28 | |||||
Light oil ($/bbl) | 101.86 | 82.88 | 93.52 | 83.22 | |||||
Heavy oil ($/bbl) | – | – | – | 76.29 | |||||
NGLs ($/bbl) | 77.70 | 72.46 | 78.65 | 77.56 | |||||
Total ($/boe) | 57.55 | 48.14 | 56.91 | 36.28 | |||||
Undeveloped Land (end of period) | |||||||||
Gross (acres) | 274,740 | 225,162 | 274,740 | 225,162 | |||||
Net (acres) | 222,181 | 171,679 | 222,181 | 171,679 | |||||
Netback and Cost | |||||||||
($ per boe) | |||||||||
Petroleum and natural gas sales | 57.55 | 48.14 | 56.91 | 36.28 | |||||
Realized gain (loss) on financial instruments | (4.59 | ) | 2.07 | (1.62 | ) | 1.39 | |||
Royalty income | 0.03 | 0.38 | 0.36 | 0.36 | |||||
Royalty expenses | (16.55 | ) | (6.60 | ) | (15.25 | ) | (2.91 | ) | |
Operating expenses, net | (5.90 | ) | (7.26 | ) | (7.09 | ) | (8.50 | ) | |
Transportation and marketing expenses | (2.56 | ) | (2.62 | ) | (2.76 | ) | (2.01 | ) | |
Operating netback | 27.98 | 34.11 | 30.55 | 24.61 | |||||
General and administrative expenses, net | (4.12 | ) | (3.85 | ) | (3.94 | ) | (5.11 | ) | |
Interest and financing expenses | (0.46 | ) | (0.22 | ) | (0.39 | ) | (0.17 | ) | |
Interest and other income | 0.10 | – | 0.09 | 0.01 | |||||
Funds from operations netback(1) | 23.50 | 30.04 | 26.31 | 19.34 | |||||
Financial | |||||||||
Petroleum and natural gas revenue ($000) | 20,228 | 11,272 | 59,690 | 21,653 | |||||
Funds from operations ($000)(1) | 8,252 | 6,977 | 27,437 | 11,430 | |||||
Per share – basic ($)(1) | 0.12 | 0.11 | 0.39 | 0.19 | |||||
Per share – diluted ($)(1) | 0.12 | 0.11 | 0.38 | 0.18 | |||||
Net income (loss) ($000) | 336 | 1,460 | 5,032 | (500 | ) | ||||
Per share – basic ($) | – | 0.02 | 0.07 | (0.01 | ) | ||||
Per share – diluted ($) | – | 0.02 | 0.07 | (0.01 | ) | ||||
Common shares outstanding | |||||||||
End of period – basic | 68,999,040 | 61,726,031 | 68,999,040 | 61,726,031 | |||||
End of period – diluted | 75,704,480 | 66,541,531 | 75,704,480 | 66,541,531 | |||||
Weighted average for the period – basic | 69,401,001 | 61,726,357 | 69,986,216 | 61,774,584 | |||||
Weighted average for the period – diluted | 71,431,314 | 62,735,423 | 71,971,207 | 62,619,387 | |||||
Capital expenditures, net ($000) | 17,499 | 16,230 | 35,129 | 23,543 | |||||
Working capital deficiency ($000)(2) | 16,855 | 10,668 | 16,855 | 10,668 | |||||
Drawn on credit facilities ($000) | 4,565 | 9,638 | 4,565 | 9,638 | |||||
Total net debt ($000) | 21,420 | 20,306 | 21,420 | 20,306 |
(1) | Funds from operations, funds from operations per share and funds from operations netback are non-GAAP measures that represent cash flow from operating activities as per the Statements of Cash Flows before the effect of decommissioning expenditures and changes in non-cash operating working capital. Per common share amounts are calculated by dividing funds from operations by the weighted average number of common shares outstanding for the period. |
(2) | Working capital deficiency is defined as current assets less current liabilities excluding the current portion of the amount drawn on the credit facilities and the fair value of financial instruments. |
Normal Course Issuer Bid
As of November 27, 2013, Manitok has purchased a total of 2,235,400 common shares of Manitok for an aggregate consideration of approximately $5.9 million (average price of $2.62 per share) in 2013, pursuant to its NCIB programs. Management believes that with potential acquisition values ranging from 5 to 7 times next year’s projected funds from operations, buying common shares of Manitok at less than 3 to 4 times next year’s projected funds from operations under its NCIB program is advantageous to Manitok shareholders with a longer term view.
2013 Guidance
Manitok has updated its guidance for projected 2013 results. Previous guidance was provided in the Corporation’s press release dated August 27, 2013. The table below provides Manitok’s revised guidance for 2013 along with a comparison to previous guidance.
Revised 2013 Guidance |
Previous 2013 Guidance |
% Variance | Funds from Operations Variance | |||||||
2013 Production | ||||||||||
Annual (boe/d) | 4,000 – 4,100 | 4,200 – 4,400 | (5 – 7 | %) | ($3.1 million | ) | ||||
% Oil and liquids | 52 | % | 53 | % | (2 | %) | ||||
Exit rate (boe/d) | 5,300 – 5,500 | 5,300 – 5,500 | – | |||||||
% Oil and liquids | 54% – 56 | % | 56% – 58 | % | (3 – 4 | %) | ||||
2013 Benchmark pricing | ||||||||||
Crude oil – WTI (US$) | 97.69 | 99.00 | (1 | %) | ||||||
$CAD/$US exchange rate | 1.03 | 1.03 | – | |||||||
Crude oil – WTI ($CAD) | 100.62 | 101.97 | (1 | %) | ($2.8 million | ) | ||||
Differential – WTI ($CAD) to Realized | (8.44 | ) | (6.00 | ) | 41 | % | ($1.6 million | ) | ||
Natural gas – AECO daily spot ($/mmbtu) | 3.13 | 3.08 | 2 | % | ||||||
Netbacks | ||||||||||
2013 Operating netback ($/boe) | 31.50 | 34.28 | (8 | %) | ($0.5 million1 | ) | ||||
2013 Funds from operations netback ($/boe) | 27.34 | 30.39 | (10 | %) | ||||||
2013 Funds from operations | $40 – $42 million | $48 – $50 million | (16 – 17 | %) | ($8.0 million | ) | ||||
Capital expenditures, net | $81 – $83 million | 72.6 million | 12 – 14 | % | ||||||
Net debt at year end | $32 – $34 million | $38 – $40 million | (15 – 16 | %) |
(1) | Difference in operating netback is due primarily to the changes in operating expenses. |
The 2013 revised guidance assumes royalties, combined operating and transportation costs net of recoveries, general and administrative expenses and interest are expected to average approximately $14.77, $9.95, $3.69 and $0.47 per boe respectively.
Expected average daily production for 2013 has been revised lower due primarily to 2 gross (1.6 net) wells that were planned to be on production in the fourth quarter of 2013 being delayed to 2014, 3 gross (1.4 net) wells coming on production at about 20% of the expected initial combined volumes, and smaller general production timing issues through the second half of the year. The lower production volumes, along with a significant increase in the oil differentials over the second half of 2013 and lower than expected crude oil prices, resulted in anticipated funds from operations for 2013 being 16 to 17% lower than previous guidance and the expected average operating netback to decrease by 8%.
Expected capital expenditures for 2013 have been increased from previous guidance due to the Lease Issuance and Drilling Commitment Agreement with EnCana Corporation (“Encana Agreement“), in the Entice area of Southeast Alberta, which is expected to add $18.4 million of capital expenditures related to the bonus payment, geological and geophysical costs and transactions costs. Excluding this $18.4 million, capital expenditures related to the Foothills is expected to decrease by $8.0 to $10.0 million from previous guidance as a result of 2 gross (1.6 net) wells being moved forward into 2014 and lower drilling and completion costs than previously anticipated.
Expected net debt has decreased from the previous guidance as result of the bought deal financing for net proceeds of approximately $23.5 million, partially offset by the decrease in expected funds from operationsand the