CALGARY, AB–(Marketwired – August 09, 2017) – Kelt Exploration Ltd. (TSX: KEL) (“Kelt” or the “Company”) has released its financial and operating results for the three and six months ended June 30, 2017. The Company’s financial results are summarized as follows:
FINANCIAL HIGHLIGHTS | Three months ended June 30 | Six months ended June 30 | |||||
(CA$ thousands, except as otherwise indicated) | 2017 | 2016 | % | 2017 | 2016 | % | |
Revenue, before royalties and financial instruments | 60,072 | 40,718 | 48 | 120,297 | 81,116 | 48 | |
Adjusted funds from operations (1) | 25,333 | 11,671 | 117 | 52,156 | 17,622 | 196 | |
Basic ($/ common share) (1) | 0.14 | 0.07 | 100 | 0.30 | 0.10 | 200 | |
Diluted ($/ common share) (1) | 0.14 | 0.07 | 100 | 0.29 | 0.10 | 190 | |
Loss and comprehensive loss | (4,869) | (20,413) | -76 | (7,136) | (46,331) | -85 | |
Basic ($/ common share) | (0.03) | (0.12) | -75 | (0.04) | (0.27) | -85 | |
Diluted ($/ common share) | (0.03) | (0.12) | -75 | (0.04) | (0.27) | -85 | |
Total capital expenditures, net of dispositions | 31,630 | 25,908 | 22 | (3,734) | 49,313 | -108 | |
Total assets | 1,203,174 | 1,260,245 | -5 | 1,203,174 | 1,260,245 | -5 | |
Bank debt, net of working capital (1) | 80,618 | 139,080 | -42 | 80,618 | 139,080 | -42 | |
Convertible debentures | 72,685 | 69,320 | 5 | 72,685 | 69,320 | 5 | |
Shareholders’ equity | 839,485 | 835,241 | 1 | 839,485 | 835,241 | 1 | |
Weighted average shares outstanding (000s) | |||||||
Basic | 175,894 | 173,818 | 1 | 175,805 | 171,321 | 3 | |
Diluted | 177,316 | 173,972 | 2 | 177,093 | 171,444 | 3 | |
(1) Refer to advisories regarding non-GAAP financial measures and other key performance indicators.
Financial Statements
Kelt’s unaudited condensed consolidated interim financial statements and related notes for the quarter ended June 30, 2017 will be available to the public on SEDAR at www.sedar.com and will also be posted on the Company’s website at www.keltexploration.com on August 9, 2017.
Kelt’s operating results for the second quarter ended June 30, 2017 are summarized as follows:
OPERATIONAL HIGHLIGHTS | Three months ended June 30 | Six months ended June 30 | |||||
(CA$ thousands, except as otherwise indicated) | 2017 | 2016 | % | 2017 | 2016 | % | |
Average daily production | |||||||
Oil (bbls/d) | 5,929 | 5,066 | 17 | 5,863 | 5,469 | 7 | |
NGLs (bbls/d) | 1,967 | 2,632 | -25 | 2,162 | 2,686 | -20 | |
Gas (mcf/d) | 76,730 | 75,060 | 2 | 74,525 | 81,577 | -9 | |
Combined (BOE/d) | 20,684 | 20,208 | 2 | 20,446 | 21,751 | -6 | |
Production per million common shares (BOE/d) (1) | 118 | 116 | 2 | 116 | 127 | -9 | |
Average realized prices, before financial instruments | |||||||
Oil ($/bbl) | 56.80 | 49.76 | 14 | 58.48 | 41.30 | 42 | |
NGLs ($/bbl) | 29.04 | 18.21 | 59 | 28.36 | 16.19 | 75 | |
Gas ($/mcf) | 3.47 | 1.97 | 76 | 3.50 | 2.16 | 62 | |
Operating netbacks ($/BOE) (1) | |||||||
Petroleum and natural gas revenue | 31.91 | 22.14 | 44 | 32.50 | 20.49 | 59 | |
Realized gain (loss) on financial instruments | (0.21) | (0.01) | 2000 | (0.10) | (0.01) | 900 | |
Average realized price, after financial instruments | 31.70 | 22.13 | 43 | 32.40 | 20.48 | 58 | |
Royalties | (2.47) | (1.65) | 50 | (3.04) | (1.49) | 104 | |
Production expense | (10.27) | (8.87) | 16 | (9.94) | (9.61) | 3 | |
Transportation expense | (3.47) | (2.89) | 20 | (3.36) | (2.79) | 20 | |
Operating netback (1) | 15.49 | 8.72 | 78 | 16.06 | 6.59 | 144 | |
Undeveloped land | |||||||
Gross acres | 777,550 | 665,010 | 17 | 777,550 | 665,010 | 17 | |
Net acres | 658,538 | 543,530 | 21 | 658,538 | 543,530 | 21 | |
(1) Refer to advisories regarding non-GAAP financial measures and other key performance indicators.
Message to Shareholders
Average production for the three months ended June 30, 2017 was 20,684 BOE per day, up 2% compared to average production of 20,208 BOE per day during the second quarter of 2016. Production during the second quarter of 2017 reflects the disposition of the majority of the Company’s oil and gas assets at Karr which included approximately 1,300 BOE per day of production. The Karr disposition was completed on January 18, 2017.
The Company’s average production during the second quarter of 2017 was below original estimates as third party outages and downtime exceeded expectations. The following downtime and outages negatively affected 2017 second quarter production: TransCanada Pipeline Ltd. restricted a portion of firm service production on the NGTL pipeline system upstream of the James River receipt area in June for approximately two weeks; turnaround operations at the McMahon Gas Plant lasted longer than originally expected; compression downtime on the Westcoast pipeline system during the McMahon plant outage resulted in partial outages at the West Stoddart Gas Plant, where the majority of the Company’s gas in British Columbia is processed; an outage at the Younger Gas Plant in British Columbia, where repairs were conducted, reduced the amount of NGL recoveries that Kelt normally realizes during the period of repairs; in June 2017, the Alliance Pipeline system declared a force majeure resulting from excavation and inspection of the upper and lower sections of its pipeline segment in the area of the slope movement near the Wapiti River requiring Kelt to shut-in significant volumes of production in both British Columbia and Alberta; and at Spirit River, the Company was required to also shut-in approximately 400 BOE per day of production that flowed through a third party gathering system. The owner of the pipeline gathering system does not intend to complete the repairs required to bring the system back to operation at this time. Kelt is currently reviewing alternative options to bring that production back on stream.
Initial production rates from recent drilling results in both British Columbia and Alberta have exceeded the Company’s estimates. As a result, despite the lower second quarter production, Kelt has not changed its full year guidance of average daily production of 23,500 BOE per day. The Company intends to review its production guidance again in September and will provide updated information at that time.
At La Glace, Alberta, the Company drilled and completed two wells in the Middle Montney. The wells were completed using gelled-water with 36 fracture stages and approximately 40 tonnes of proppant per stage. The well located at 02/13-33-074-08W6 had an IP30 rate (gross estimated sales) of 790 BOE per day of which 90% was oil and NGLs. The second well located at 02/04-23-074-08W6 had an IP30 rate (gross estimated sales) of 888 BOE per day of which 69% was oil and NGLs. Given the lower capital expenditures per well and the resulting quick payback on these wells, at under six months in the current commodity price environment, Kelt has drilled two additional wells at La Glace in July 2017.
At Inga, British Columbia, the Company drilled its third Middle Montney well on its large contiguous land block. The well was completed using slick-water with 46 fracture stages and approximately 70 tonnes of proppant per stage. The well located at 02/15-33-087-23W6 had an IP24 rate (gross estimated sales) of 2,157 BOE per day of which 81% was oil and NGLs. This is the highest Middle Montney initial production rate recorded to date at Inga/Fireweed. In the current commodity price environment, given the high oil content of the initial production, this well is expected to payback in approximately six months. With the success to date in the Middle Montney, Kelt expects to drill additional Middle Montney wells at Inga during the second half of 2017 and in 2018.
At Pipestone/Wembley, Alberta where the Company has recently increased its land position to 59,080 acres (92 sections) of lands with Montney rights, Kelt has drilled its first horizontal exploratory well located at 00/04-01-072-08W6. This well has now been completed using slick-water with 50 fracture stages and approximately 70 tonnes of proppant per stage. Initial production results are expected to be available in September 2017.
At Inga/Stoddart, British Columbia where the Company has 104,862 acres (164 sections) of lands with Baldonnel rights, Kelt has drilled its first horizontal exploratory well located at 00/13-29-087-21W6. This well is currently being completed using slick-water with 30 planned fracture stages and approximately 26 tonnes of proppant per stage.
Commodity prices have improved from 2016 levels and have shown significant gains in the second quarter of 2017 compared to the second quarter of 2016. Kelt’s realized average oil price during the second quarter of 2017 was $56.80 per barrel, up 14% from $49.76 per barrel in the second quarter of 2016. The realized average NGLs price during the second quarter of 2017 was $29.04 per barrel, up 59% from $18.21 per barrel in the corresponding quarter of 2016. Kelt’s realized average gas price for the second quarter of 2017 was $3.47 per MCF, up 76% from $1.97 per MCF in the second quarter of the previous year.
The Company continues to realize higher average gas prices compared to the AECO index price through its gas market diversification strategy. In British Columbia, where there have been gas egress congestion and bottlenecks in the past, for the upcoming gas year (November 1, 2017 to October 31, 2018), Kelt has contracted service for approximately 25,000 MMBtu per day of gas sales for its British Columbia production. Approximately 15,000 MMBtu per day will be delivered to the Station 2 Hub and Kelt will receive the Sumas Hub USD Monthly Index price less US$0.695 per MMBtu. Approximately 10,000 MMBtu per day will be delivered to an Alliance pipeline receipt point and Kelt will receive the Chicago Hub Gas Daily Index price less transportation charges. As a result, Kelt will have minimal to no exposure to Station 2 pricing in its British Columbia gas market portfolio. In Alberta, the Company has contracts in place to sell 15,000 MMBtu per day of gas at NIT and to receive the Malin Hub USD Index price less US$0.70 per MMBtu (November 1, 2017 to October 31, 2020) and 23,700 MMBtu per day of gas at the Dawn hub in southern Ontario less transportation charges (November 1, 2017 to October 31, 2020). These contracts provide Kelt with gas market diversification and ensure that the Company’s future gas sales revenue is not subject to the risks associated with a single market.
For the three months ended June 30, 2017, revenue was $60.1 million and adjusted funds from operations was $25.3 million ($0.14 per share, diluted), compared to $40.7 million and $11.7 million ($0.07 per share, diluted) respectively, in the second quarter of 2016. At June 30, 2017, bank debt, net of working capital was $80.6 million, down 42% from $139.1 million at June 30, 2016.
Capital expenditures incurred during the three months ended June 30, 2017, prior to property dispositions, were $35.0 million. The Company spent $19.6 million (56%) on drilling and completion operations, $14.1 million (40%) on facilities, pipelines and equipment and $1.2 million (4%) on land and seismic. In addition, during the second quarter of 2017, Kelt received cash proceeds of $3.3 million from minor property dispositions.
Kelt has recently moved to development drilling from multi-well pads as part of its future development plan for its vast corporate Montney acreage. Capital efficiencies gained from pad drilling and improved completion results with increased fracture stages, greater proppant tonnage and high intensity pump rates have resulted in short payback periods in the current commodity price environment. The tables below show the estimated payback of capital incurred to drill and complete all new Montney wells that the Company has brought on production in 2017 (except the Inga 00/14-24-087-23W6 well which was brought on production on December 12, 2016). Two Montney wells drilled at Progress are not included in Table 1 as these wells are currently in the process of being brought on stream.
Table 1 – Paybacks for 2017 Montney Development Wells: | ||||||||||
Well | Drill & Complete Cost ($ MM) [1] | Initial Test Date | Production Start Date [2] | Actual Cumulative to May 31, 2017 [3] | Remaining to Payback [4] | Payback Period (years) | Last Month’s Production Rate at Payback (BOE/d) | |||
Production (MBOE) | Operating Income ($ MM) | Operating Netback ($/BOE) | Production Estimate (MBOE) | Operating Income Estimate ($ MM) | ||||||
Pouce Coupe 02/06-18-078-11W6 | 4.8 | 2017-01-26 | 2017-01-26 | 150.7 | 4.8 | 31.90 | 22.8 | 0.5 | 0.4 | 761 |
Pouce Coupe 03/07-18-078-11W6 | 4.1 | 2017-01-26 | 2017-01-26 | 125.4 | 4.0 | 31.84 | 23.8 | 0.6 | 0.4 | 792 |
Pouce Coupe 04/07-18-078-11W6 | 5.0 | 2017-01-24 | 2017-03-03 | 101.4 | 3.0 | 30.00 | 83.8 | 2.2 | 0.7 | 440 |
Pouce Coupe 05/07-18-078-11W6 | 4.3 | 2017-01-23 | 2017-03-08 | 105.0 | 3.2 | 30.08 | 40.2 | 1.2 | 0.4 | 578 |
Pouce Coupe 00/01-09-078-11W6 | 5.0 | 2017-02-21 | 2017-03-11 | 89.8 | 3.0 | 33.50 | 70.3 | 2.1 | 0.6 | 450 |
Pouce Coupe 03/16-25-077-13W6 | 5.8 | 2017-02-25 | 2017-06-19 | 26.5 | 0.4 | 13.83 | 426.1 | 5.8 | 0.8 | 1,061 |
La Glace 02/13-33-074-08W6 | 3.8 | 2017-04-01 | 2017-04-01 | 42.8 | 1.8 | 42.86 | 56.0 | 2.1 | 0.5 | 406 |
La Glace 02/04-23-074-08W6 | 4.0 | 2017-05-26 | 2017-05-26 | 2.1 | 0.1 | 26.88 | 131.8 | 4.2 | 0.7 | 347 |
Notes: Refer to explanatory notes provided under Table 2.
In addition to favourable economic results from its Montney development drilling program, the Company expects to achieve short paybacks on its capital incurred on Montney delineation and step-out wells. A move to pad drilling on these newly de-risked lands should result in further improvements in capital efficiencies in the future.
Table 2 – Paybacks for 2017 Montney Delineation/Step-out Wells: | ||||||||||
Well | Drill & Complete Cost ($ MM) [1] | Initial Test Date | Production Start Date [2] | Actual Cumulative to May 31, 2017 [3] | Remaining to Payback [4] | Payback Period (years) | Last Month’s Production Rate at Payback (BOE/d) | |||
Production (MBOE) | Operating Income ($ MM) | Operating Netback ($/BOE) | Production Estimate (MBOE) | Operating Income Estimate ($ MM) | ||||||
Inga 00/14-24-087-23W6 [ Middle Montney ] |
6.5 | 2016-12-12 | 2016-12-12 | 135.6 | 4.6 | 34.17 | 58.2 | 2.0 | 0.8 | 449 |
Fireweed C-31-I/94-A-12 [ Upper Montney ] |
6.9 | 2017-01-16 | 2017-01-16 | 142.9 | 3.6 | 25.13 | 151.5 | 3.3 | 1.4 | 313 |
Stoddart 00/08-17-087-22W6 [ Upper Montney ] |
7.4 [5] | 2017-03-22 | 2017-04-25 | 32.6 | 0.9 | 28.02 | 259.6 | 6.5 | 2.6 | 177 |
Inga 02/15-33-087-23W6 [ Middle Montney ] |
5.5 | 2017-07-06 | 2017-07-13 | – | – | – | 193.7 | 5.7 | 0.5 | 656 |
Notes:
[1] Half-cycle capital – equipment and tie-in costs for delineation/step-out wells are not included in the payback period calculation, as the initial tie-in costs for single wells will eventually benefit additional wells drilled from the same pad. Equipment and tie-in costs for pad wells are on average an incremental $300,000 per well and are included in the payback period calculation for development wells.
[2] Production Start Date is the date when the well commenced steady production after tie-in operations were completed. The payback period is calculated from this date.
[3] Actual production and operating income cumulative to date is up to May 31, 2017 and includes any production and operating income generated during the test period, prior to the Production Start Date.
[4] Estimated operating income required to payback is calculated based on actual sales prices received to date. Estimated future production is calculated based on internally generated production forecasts/decline curves for each respective well. Actual production for June and July 2017, based on field estimates, is included in estimated future production.
[5] During completion operations, the Stoddart 8-17 well experienced fracking and drill-out problems which added approximately $1.0 million to the completion costs.
The Company’s Board of Directors has agreed to increase the 2017 capital expenditure budget by a net $10.0 million. Total exploration and development capital expenditures planned for 2017 are $191.0 million (previously $173.0 million) and proceeds from property dispositions are expected to be $111.0 million (previously $103.0 million), resulting in a net capital expenditure budget of $80.0 million (previously $70.0 million). The increase in the capital expenditure budget reflects an additional $18.0 million for infrastructure expenditures and additional proceeds from minor property dispositions in the amount of $8.0 million ($3.3 million of which was already completed at June 30, 2017 and the balance is an estimate for further transactions expected to occur in the second half of 2017).
On July 31, 2017, the Company completed the purchase of a major infrastructure package for $12.5 million. After a new lease has been surveyed and built, this infrastructure package will be moved from its existing location in northeastern British Columbia and installed on a new site at Inga, British Columbia, in close proximity to the Company’s existing Inga facility located at 15-03-088-23W6. The infrastructure package includes four 4,700 horse power gas compressors with aggregate capacity of 100 MMCF per day, two 50 MMCF per day gas dehydration units, a fuel gas conditioning skid, a high pressure flare system, four 750 barrel tanks, a vapor recovery unit, instrument air compressors, three electric power generators, a master control centre building and several other buildings and associated equipment. This infrastructure purchase is expected to lower future production expenses regardless of whether the Company elects to construct its own gas plant at Inga, or alternatively, continues to process gas through third party facilities in British Columbia.
Kelt has also commenced installation of blending facilities at its three main oil terminals located at Inga, La Glace and Progress, which are now pipeline connected to oil sales and water injection. These new facilities are expected to provide the Company with higher price realizations for its oil and butane sales in each of these areas and are anticipated to be completed prior to year-end.
The Company is well positioned financially to execute its capital program during the remainder of 2017 and expects to enter 2018 with strong operational momentum.
Management looks forward to updating shareholders with 2017 third quarter results on or about November 9, 2017.