(MENAFN- GlobeNewsWire - Nasdaq) itemprop="articleBody">CALGARY, Alberta, March 13, 2019 (GLOBE NEWSWIRE) -- TransGlobe Energy Corporation (AIM & TSX: 'TGL' & NASDAQ: 'TGA')
This Announcement contains inside information as defined in Article 7 of the Market Abuse Regulation No. 596/2014 ('MAR'). Upon the publication of this Announcement, this inside information is now considered to be in the public domain.
TransGlobe Energy Corporation ('TransGlobe' or the 'Company') is pleased to announce its financial and operating results for the three months and year ended December 31, 2018. All dollar values are expressed in United States dollars unless otherwise stated. TransGlobe's audited Consolidated Financial Statements together with the notes related thereto, as well as TransGlobe's Management's Discussion and Analysis for the years ended December 31, 2018 and 2017, are available on TransGlobe's website at www.trans-globe.com .
2018:
- Produced an average of 14,439 boe/d and sold 15,013 boe/d as compared to 15,506 boe/d and 16,849 boe/d in 2017, a 7% and 11% decrease year over year;
- Funds flow from operations increased to $63.3 million ($0.87 per share), up from $55.6 million ($0.77 per share) in 2017, a 14% increase;
- Reported net earnings of $15.7 million ($0.22 per share), inclusive of a $14.5 million impairment loss and $9.3 million unrealized gain on derivative commodity contracts;
- Resumed paying a dividend with a $0.035 per common share payment ($2.5 million) paid September 14, 2018 to shareholders of record August 31, 2018;
- Reduced inventoried entitlement crude oil in Egypt year over year to 568 mbbls from 777 mbbls, which made a positive contribution to funds flow from operations during the year;
- Ended the year with positive working capital of $51.0 million (including cash and cash equivalents of $51.7 million) at December 31, 2018;
- Spent $40.7 million on exploration and development activities in both Egypt and Canada;
- Drilled 12 wells in Egypt (four exploration, and eight development), resulting in one discovery and eight development oil wells;
- Drilled a light oil discovery at South Ghazalat which tested at a combined rate of 3,840 bbl/d from the Upper and Lower Bahariya formation;
- Completed Phase 2 expansions of the West Bakr K and H stations to double processing capacity;
- Drilled six (five net) Hz multi-stage Cardium development oil wells in Canada; and
- Ended the year with 44.1 mmboe of 2P reserves, down 4% from 2017 year end of 45.9 mmboe.
2019 (to date):
- January average production of 15.4 mboe/d, February average production of 15.0 mboe/d;
- Drilled a successful oil well at M-10 Twin which was placed on production (~ 495 bbl/d) in February;
- Drilled a potential oil well at NWG 38A-8 which will be completed and tested in March;
- Progressed and submitted a potential development plan for the South Ghazalat 6X discovery in February, targeting Q4-2019 production;
- Equipped and tied in six Cardium oil wells (2018 program) in the Harmattan area, Canada during January; and
- Declared a $0.035 per share ($2.5 million) dividend payable April 18, 2019 to shareholders of record on March 29, 2019.
A conference call to discuss TransGlobe's 2018 fourth quarter and year end results presented in this news release will be held Wednesday, March 13, 2019 at 8:00 AM Mountain Time (10:00 AM Eastern Time/14:00 PM London Time) and is accessible to all interested parties by dialing 1-416-406-0743 or toll free at 1-800-952-5114. The webcast may be accessed at http://www.gowebcasting.com/9893.
FINANCIAL AND OPERATING RESULTS
Additional financial information is provided for in the Company's audited Consolidated Financial Statements together with the notes related thereto, as well as TransGlobe's Management's Discussion and Analysis for the years ended December 31, 2018 and 2017. These documents, along with other documents affecting the rights of securityholders and other information relating to the Company, may be found on SEDAR at www.sedar.com and in the Company's Annual Report on Form 40-F for the fiscal year ended December 31, 2018, filed on EDGAR at www.sec.gov.
(US$000s, except per share, price, volume amounts and % change)
Three months ended December 31 Year ended December 31
Financial 2018 2017 % Change 2018 2017 % Change
Petroleum and natural gas sales 72,628 72,954 — 299,142 252,591 18
Petroleum and natural gas sales, net of royalties 40,605 40,725 — 176,227 148,464 19
Realized derivative loss on commodity contracts 8,057 2,496 223 16,386 2,871 471
Unrealized derivative (gain) loss on commodity contracts (29,492 ) 7,584 (489) (9,335 ) 7,970 (217)
Production and operating expense 13,116 11,083 18 53,298 51,005 4
Selling costs 450 569 (21) 2,103 2,495 (16)
General and administrative expense 2,005 3,636 (45) 18,678 15,253 22
Depletion, depreciation and amortization expense 8,214 10,401 (21) 34,291 40,036 (14)
Income taxes 6,612 5,715 16 26,340 21,819 21
Cash flow generated by operating activities 9,822 44,263 (78) 69,192 59,450 16
Funds flow from operations1 8,842 17,018 (48) 63,282 55,592 14
Basic per share 0.12 0.24 0.87 0.77
Diluted per share 0.12 0.24 0.86 0.77
Net earnings (loss) 30,719 (2,382 ) 1,390 15,677 (78,736 ) 120
Basic per share 0.43 (0.03 ) 0.22 (1.09 )
Diluted per share 0.43 (0.03 ) 0.22 (1.09 )
Capital expenditures 17,433 9,078 92 40,706 38,159 7
Dividends paid — — 2,527 —
Dividends paid per share — — 0.035 —
Working capital 50,987 50,639 1 50,987 50,639 1
Long-term debt, including current portion 52,355 69,999 (25) 52,355 69,999 (25)
Common shares outstanding
Basic (weighted average) 72,206 72,206 — 72,206 72,206 —
Diluted (weighted average) 72,706 72,206 1 72,631 72,206 1
Total assets 318,296 327,702 (3) 318,296 327,702 (3)
Operating
Average production volumes (boe/d) 15,270 13,952 9 14,439 15,506 (7)
Average sales volumes (boe/d) 14,483 16,249 (11) 15,013 16,849 (11)
Inventory (mbbls) 568 777 (27) 568 777 (27)
Average sales price ($ per boe) 54.51 48.80 12 54.59 41.07 33
Operating expense ($ per boe) 9.84 7.41 33 9.73 8.29 17
1 Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies.
OPERATIONS UPDATE
ARAB REPUBLIC OF EGYPT EASTERN DESERT
West Gharib, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
No wells were drilled during the fourth quarter.
Production
Production from West Gharib averaged 4,512 bbls/d during the fourth quarter, a 6% (281 bbls/d) decrease from the previous quarter primarily due to natural declines.
Production was 4,431 bbls/d during January and 4,024 bbls/d during February. Production variances during January and February were primarily due to natural declines.
Sales
TransGlobe sold 221,732 barrels of inventoried entitlement crude oil (after royalties and tax) to a third-party for $15.2 million in the fourth quarter.
Quarterly West Gharib Production (bbls/d) 2018
Q-4 Q-3 Q-2 Q-1
Gross production rate 5,015 5,741 6,389 6,683
TransGlobe production (inventoried) sold 109 (207) (297) 21
Total sales 4,621 4,587 4,718 5,125
Government share (royalties and tax) 2,211 2,349 2,459 2,504
TransGlobe sales (after royalties and tax)1 2,410 2,238 2,259 2,621
Total Sales 4,621 4,587 4,718 5,125
1 Under the terms of the West Gharib Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.
West Bakr, Arab Republic of Egypt (100% working interest, operated) Operations and Exploration
No wells were drilled during the fourth quarter.
Subsequent to the year end, the Company finished drilling the M-10 replacement well (M-10 Twin), which was completed as an Asl A oil well during February. The original M-10 well (drilled and producing since 2000) was suspended and abandoned due to casing integrity issues encountered during a remedial water shut off program in September 2018. The M-10 Twin well was placed on production in February and is currently producing ~495 bbls/d.
Production
Production from West Bakr averaged 7,323 bbls/d to TransGlobe during the fourth quarter, a 20% (1,197 bbls/d) increase from the previous quarter. The increased production is primarily due to the continued performance of the M field infill wells (M-North and M-South) drilled in 2018 along with the well optimization program associated with the K station Phase 2 system expansion. Construction of the K station Phase 3, to add a third process train and triple the original fluid handling capacity to ~45,000 barrels per day (of fluid) has commenced, targeting a mid 2019 completion.
Production increased to 7,370 bbls/d during January and to 7,968 bbls/d during February. Production increases during January and February were primarily due to successful well optimization and recompletions in the H field following the completion of the H station Phase 2 system expansion in late 2018.
Sales
TransGlobe sold 228,268 barrels of inventoried entitlement crude oil (after royalties and tax) to a third-party for $15.5 million in the fourth quarter.
Quarterly West Bakr Production (bbls/d) 2018
Q-4 Q-3 Q-2 Q-1
Gross production rate 7,323 6,126 5,747 5,274
TransGlobe production (inventories) sold (485) (1,700) 6,235 (2,136)
Total sales 6,838 4,426 11,982 3,138
Government share (royalties and tax) 4,357 3,646 3,419 3,138
TransGlobe sales (after royalties and tax)1 2,481 780 8,563 —
Total sales 6,838 4,426 11,982 3,138
1 Under the terms of the West Bakr Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.
North West Gharib, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
During the quarter, the Company drilled the NWG 38A-7 well as a potential water injector which encountered oil in Red Bed formation. The well extended the known oil column height structurally down an additional 101 feet to a total of 445 feet for the NWG 38 pool. NWG 38A-7 was completed (unstimulated) and placed on production as a Red Bed oil well at an initial production rate of ~ 360 bbls/d. Based on the positive results at NWG 38A-7, the Company commenced wellsite construction at NWG 38A-8, located approximately 0.4 km south of NWG 38A-7, targeting the Red Bed pool in a structurally lower position to provide water injection/reservoir pressure support for the 38A pool.
Subsequent to year end, the NWG 38A-8 well was drilled to a total depth of 5,350 feet and cased as a potential Red Bed oil well. Based on wireline logs and samples (MDT), it appears that NWG 38A-8 has extended the NG 38A red bed oil pool to the south. The well is scheduled for completion and testing later this month.
Production
Production from NWG averaged 1,135 bbls/d to TransGlobe during the fourth quarter, an 11% (115 bbls/d) increase from the previous quarter, primarily due to production from NWG 38A-7.
Production averaged 1,199 bbls/d during January, and 1,246 bbls/d during February.
Sales
TransGlobe did not sell its entitlement share of production (after royalties and tax) from NWG during the quarter.
Quarterly North West Gharib Production (bbls/d) 2018
Q-4 Q-3 Q-2 Q-1
Gross production rate 1,135 1,020 1,151 1,399
TransGlobe production (inventoried) sold) (411) 2,065 (417) (507)
Total sales 724 3,085 734 892
Government share (royalties and tax) 724 650 734 892
TransGlobe sales (after royalties and tax)1 — 2,435 — —
Total sales 724 3,085 734 892
1 Under the terms of the North West Gharib Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.
WESTERN DESERT
South Alamein, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
No wells were drilled in the quarter.
The Company has resubmitted a request for military access to drill the SA 24X Jurassic exploration prospect and entered into extension discussions with the EGPC, which are ongoing.
South Ghazalat, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
During the quarter, the Company drilled the SGZ 6X exploration well to a total depth of 5,195 feet and cased as a potential Bahariya light oil discovery. Subsequently, the Company tested a combined 3,840 barrels per day of light oil from the upper and lower Bahariya. The lower Bahariya formation flowed naturally at an average rate of 2,437 barrels per day of light (38 API) oil, 21 barrels per day of water and 1.4 million cubic feet of natural gas per day on a 40/64 inch choke from a 42 foot perforated interval. A total of 918 barrels of oil and 7 barrels of water were produced during the 10 hour test. The upper Bahariya formation flowed at an average rate of 1,403 barrels per day of light (35 API) oil, 210 barrels per day of water and 1.0 million cubic feet of natural gas per day on a 64/64 inch choke from a 23 foot perforated interval. A total of 456 barrels of oil and 65 barrels of water were produced during the 8 hour test. Although encouraging, test rates are not necessarily indicative of long-term performance or ultimate recovery.
In December, the Company filed a declaration of a Commercial Discovery to initiate early development discussions with EGPC.
Subsequent to year end, the Company filed an initial Development plan for the SGZ 6X discovery with EGPC in late February. Subject to government approval of the proposed development plan, the Company is targeting initial production by Q4 2019.
Concurrently, the Company has identified potential drilling locations targeting the SGZ 6X Bahariya pool and commenced the well permitting process. In addition, the Company has initiated a project to merge and reprocess two existing 3D seismic surveys in the 6X area of the concession.
With the completion of SGZ 6X well, the Company has met the financial commitments for the current exploration phase of the concession. The current exploration phase (as extended) expires May 6, 2019 with the option to enter into the final 18 month exploration phase.
North West Sitra, Arab Republic of Egypt (100% working interest, operated)
Operations and Exploration
The Company met all of the work commitments for the first exploration phase of the concession. Based on the 2018 drilling results, the Company did not enter the next exploration phase and relinquished the concession effective January 7, 2019.
CANADA
Operations and Exploration
During the quarter, the Company drilled and cased three Cardium oil wells (two gross (1.5 net) one-mile horizontal wells and a two-mile extended reach horizontal well) which completed the 2018 six well drilling program. The six (five net) horizontal wells were completed and fracture stimulated (~40 stages per mile) during the quarter and placed on production in early 2019. Concurrently, the Company completed construction of a 2.7 kilometer pipeline to connect the 2018 wells (which were drilling from the same pad) to the Company's central production facility. The wells were equipped and placed on production during January.
Production
Production from Canada averaged 2,301 boe/d during the fourth quarter, a 4% (92 boe/d) decrease from the previous quarter, due to natural declines and curtailed production in response to low prices and increased differentials late in the quarter.
Production averaged 2,494 boe/d in January and 1,758 boe/d in February. The increased production in January was primarily due to the new wells coming on production during the month which was partially offset by decreased ethane sales. Since January, the main gas processing plant (third party) for the Company's gas production shut down their deep cut ethane extraction plant due to low prices for ethane and the associated pipeline egress issues in Alberta. The ethane will remain in the sales gas, which is sold with a higher energy content. It is anticipated that the loss of ethane sales will be generally revenue neutral, due to the low prices for ethane. The Company had been selling ~ 300 boepd of ethane, which is now sold as natural gas with a higher energy content. In February, production was lower due to a two week shut down of the central production facility to replace a burner in the main treater. The repair work was further exacerbated by extremely cold weather during the month of February, which also slowed the restart of production following the facility repairs. Production was fully restored by the end of February and has averaged approximately 2,400 boe/d to date in March.
Quarterly Canada Production (boe/d) 2018
Q-4 Q-3 Q-2 Q-1
Canada crude oil (bbls/d) 495 567 497 675
Canada NGLs (bbls/d) 829 576 521 894
Canada natural gas (mcf/d) 5,865 5,695 5,094 6,176
Total production (boe/d) 2,301 2,393 1,867 2,598
SELECTED ANNUAL INFORMATION
($000s, except per share, price and volume amounts) 2018 % Change 2017 % Change 20165
Operations
Average production volumes
Crude oil (bbls/d) 12,708 (5) 13,411 11 12,033
NGLs and condensate (bbls/d) 780 (21) 988 28065 34
Natural gas (mcf/d) 5,707 (14) 6,644 27895 230
Total (boe/d) 14,439 (7) 15,506 28 12,105
Average sales volumes
Crude oil (bbls/d) 13,282 (10) 14,754 33 11,093
NGLs and condensate (bbls/d) 780 (21) 988 28065 34
Natural gas (mcf/d) 5,707 (14) 6,644 27895 230
Total (boe/d) 15,013 (11) 16,849 51 11,165
Average realized sales prices
Crude oil ($/bbl) 59.57 33 44.71 49 30.05
NGLs and condensate ($/bbl) 27.17 27 21.31 24 17.20
Natural gas ($/mcf) 1.26 (26) 1.70 (6) 1.81
Total oil equivalent ($/boe) 54.59 33 41.07 37 29.94
Inventory (mbbls) 568.1 (27) 776.8 (39) 1,265.1
Petroleum and natural gas sales 299,144 18 252,591 106 122,360
Petroleum and natural gas sales, net of royalties 176,227 19 148,464 135 63,134
Cash flow generated by (used in) operating activities 69,192 16 59,450 5,682 (1,065 )
Funds flow from operations1 63,282 14 55,592 765 (8,361 )
Funds flow from operations per share:
- Basic 0.87 0.77 (0.12 )
- Diluted2 0.86 0.77 (0.12 )
Net earnings (loss) 15,677 120 (78,736 ) 10 (87,665 )
Net earnings (loss) per share:
- Basic 0.22 (1.09 ) (1.21 )
- Diluted2 0.22 (1.09 ) (1.21 )
Capital expenditures 40,706 7 38,159 43 26,658
Property expenditures — — — (100) 59,475
Dividends paid 2,527 — — —
Dividends paid per share 0.035 — — —
Total assets 318,296 (3) 327,702 (19) 406,142
Cash and cash equivalents 51,705 9 47,449 51 31,468
Working capital 50,987 1 50,639 402 (16,764 )
Convertible debentures — — — — 72,655
Note payable — — — — 11,162
Total long-term debt, including current portion 52,355 (25) 69,999 100 —
Net debt-to-funds flow from operations ratio3 0.02 0.35 (12.00 )
Reserves
Total proved (mmboe)4 26.9 (2) 27.5 (8) 29.9
Total proved plus probable (mmboe)4 44.1 (4) 45.9 (8) 50.0
1 Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
2 Funds flow from operations per share (diluted) and net earnings (loss) per share (diluted) was not impacted by the convertible debentures for the year ended December 31, 2016 as the convertible debentures were not dilutive in this year.
3 Net debt-to-funds flow from operations ratio is a measure that represents total long-term debt, note payable, and convertible debentures (including the current portion) net of working capital, over funds flow from operations for the trailing 12 months, and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
4 As determined by the Company's 2018 & 2017 independent reserves evaluator, GLJ Petroleum Consultants Ltd. ('GLJ'), in their reports dated January 22, 2019 and January 9, 2018, with effective dates of December 31, 2018 and December 31, 2017. As determined by the Company's, 2016 independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their report dated January 18, 2017 with an effective date of December 31, 2016. The reports of GLJ and DeGolyer have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time and National Instrument 51-101.
5 The 2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan assets were acquired in a transaction that closed on December 20, 2016 (effective December 1, 2016).
In 2018 compared with 2017, TransGlobe: Reported a 7% decrease in production volumes compared to 2017. In Egypt, the decrease was primarily due to natural declines in production, partially offset by drilling and well optimization results. In Canada, production was lower due to the planned Harmattan turnaround, unscheduled compressor maintenance in November and curtailments due to low pricing;
Ended 2018 with inventoried crude oil of 568 mbbls, a decrease of 209 mbbls over inventoried crude oil levels at December 31, 2017;
Increased petroleum and natural gas sales by 18% due to a 33% increase in realized prices, partially offset by an 11% decrease in sales volumes;
Reported positive funds flow from operations of $63.3 million (2017 - $55.6 million);
Ended the year with positive working capital of $51.0 million, including $51.7 million in cash and cash equivalents as at December 31, 2018;
Reported net earnings of $15.7 million (2017 - net loss of $78.7 million). The 2018 net earnings includes a $14.5 million impairment loss on the Company's exploration and evaluation assets and a $9.3 million unrealized derivative gain on commodity contracts. Excluding the impairment loss and the unrealized gain on derivative commodity contracts, the Company would have achieved net earnings of $20.9 million;
Spent $40.7 million on capital expenditures, funded entirely from cash flow from operations and cash on hand;
Paid a dividend of $0.035 per share ($2.5 million) on September 14, 2018 to shareholders of record on August 31, 2018; and
Repaid $17.8 million of long-term debt with cash on hand. OPERATING RESULTS AND NETBACK
Daily Volumes, Working Interest before Royalties (boe/d)
Production Volumes
2018 2017
Egypt crude oil (bbls/d) 12,150 12,822
Canada crude oil (bbls/d) 558 589
Canada NGLs (bbls/d) 780 988
Canada natural gas (mcf/d) 5,707 6,644
Total Company (boe/d) 14,439 15,506
Sales Volumes (excludes volumes held as inventory)
2018 2017
Egypt crude oil (bbls/d) 12,724 14,165
Canada crude oil (bbls/d) 558 589
Canada NGLs (bbls/d) 780 988
Canada natural gas (mcf/d) 5,707 6,644
Total Company (boe/d) 15,013 16,849
Netback
Consolidated netback
2018 2017
($000s, except per boe amounts)1 $ $/boe $ $/boe
Petroleum and natural gas sales 299,144 54.59 252,591 41.07
Royalties2 122,917 22.43 104,127 16.93
Current taxes2 26,340 4.81 21,819 3.55
Production and operating expenses 53,298 9.73 51,005 8.29
Selling costs 2,103 0.38 2,495 0.41
Netback 94,486 17.24 73,145 11.89
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2018 and December 31, 2017 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2018 and December 31, 2017).
2 Royalties and taxes are settled on a production basis, royalties and taxes attributable to oil sales fluctuates dependent upon the sale of inventoried entitlement oil.
Egypt - total
2018 2017
($000s, except per bbl amounts)1 $ $/bbl $ $/bbl
Oil sales 278,111 59.88 230,323 44.55
Royalties2 120,271 25.90 99,336 19.21
Current taxes2 26,340 5.67 21,819 4.22
Production and operating expenses 45,562 9.81 44,705 8.65
Selling costs 2,103 0.45 2,495 0.48
Netback 83,835 18.05 61,968 11.99
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2018 and December 31, 2017 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2018 and December 31, 2017).
2 Royalties and taxes are settled on a production basis, royalties and taxes attributable to oil sales fluctuates dependent upon the sale of inventoried entitlement oil.
The netback per bbl in Egypt increased by 51% in 2018 compared to 2017. The increase was due to a 34% higher realized oil price offset by an increase in production and operating expenses of 13%. The increase in production and operating expenses was primarily due to an extensive workover program and higher diesel, transportation and service costs due to stronger oil prices. Royalties and taxes as a percentage of revenue were 53% in 2018 (2017 - 53%). Royalties and taxes are settled on a production basis, therefore, the correlation of royalties and taxes to oil sales fluctuates depending on the timing of entitlement oil sales. If sales volumes had been equal to production volumes during the year, royalties and taxes as a percentage of revenue would have been 55% (2017 - 58%). In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the PSCs dictate. In periods when the Company sells more than its entitlement production, royalties and taxes as a percentage of revenue will be lower than the terms the PSCs dictate.
The average selling price for the year ended December 31, 2018 was $59.88/bbl (2017 - $44.55/bbl), which was $11.18/bbl lower (2017 - $9.70/bbl) than the average Dated Brent oil price of $71.06/bbl for 2018 (2017 - $54.25/bbl). The difference between the average Dated Brent price and the Company's realized selling price is due to a gravity/quality adjustment and is impacted by the timing of direct sales.
Canada
2018 2017
($000s, except per boe amounts) $ $/boe $ $/boe
Crude oil sales 10,666 52.37 10,464 48.67
Natural gas sales 2,632 7.58 4,120 10.19
NGL sales 7,735 27.17 7,684 21.31
Total sales 21,033 25.17 22,268 22.73
Royalties 2,646 3.17 4,791 4.89
Production and operating expenses 7,736 9.26 6,300 6.43
Netback 10,651 12.74 11,177 11.41
The netback in Canada was $12.74 per boe in 2018, an increase of $1.33 per boe (12%) compared to 2017. The increase is mainly due to an 11% higher realized sales price and 35% lower royalties. This was partially offset by a 44% increase in production and operating expenses attributable to the planned turnaround at Harmattan in Q2-2018, workovers and higher costs due to stronger oil prices.
In 2018, the Company's Canadian operations incurred $2.1 million lower royalty costs than 2017. The reduction in royalties is primarily due to Gas Cost Allowance (GCA) rebates received in 2018. Royalties amounted to 13% of petroleum and natural gas sales revenue during 2018 compared to 22% during the prior year. TransGlobe pays royalties to the Alberta provincial government and landowners in accordance with the established royalty regime. In Alberta, Crown royalty rates are based on reference commodity prices, production levels and well depths, and are offset by certain incentive programs, which usually have a finite period of time and are in place to promote drilling activity by reducing overall royalty expense.
Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss)
(Expressed in thousands of US Dollars, except per share amounts)
Years Ended December 31
2018 2017
REVENUE
Petroleum and natural gas sales, net of royalties $ 176,227 $ 148,464
Finance revenue 570 108
176,797 148,572
EXPENSES
Production and operating 53,298 51,005
Selling costs 2,103 2,495
General and administrative 18,688 15,253
Foreign exchange (gain) loss (289 ) 194
Finance costs 5,075 6,233
Depletion, depreciation and amortization 34,291 40,036
Asset retirement obligation accretion 270 256
Loss on financial instruments 7,051 10,992
Impairment loss 14,500 79,025
Gain on disposition of assets (207 ) —
134,780 205,489
Earnings (loss) before income taxes 42,017 (56,917 )
Income tax expense – current 26,340 21,819
NET EARNINGS (LOSS) $ 15,677 $ (78,736 )
OTHER COMPREHENSIVE INCOME (LOSS)
Currency translation adjustments (3,732 ) 2,793
COMPREHENSIVE INCOME (LOSS) $ 11,945 $ (75,943 )
Earnings (loss) per share
Basic $ 0.22 $ (1.09 )
Diluted $ 0.22 $ (1.09 )
Consolidated Balance Sheets
(Expressed in thousands of US Dollars)
As at As at
December 31, 2018 December 31, 2017
ASSETS
Current
Cash and cash equivalents $ 51,705 $ 47,449
Accounts receivable 12,014 18,090
Derivative commodity contracts 1,198 —
Prepaids and other 5,385 4,745
Product inventory 8,692 11,474
78,994 81,758
Non-Current
Derivative commodity contracts 171 —
Intangible exploration and evaluation assets 36,266 41,478
Property and equipment
Petroleum and natural gas assets 195,263 200,981
Other assets 3,079 3,485
Deferred taxes 4,523 —
$ 318,296 $ 327,702
LIABILITIES
Current
Accounts payable and accrued liabilities $ 28,007 $ 27,104
Derivative commodity contracts — 4,015
28,007 31,119
Non-Current
Derivative commodity contracts — 3,955
Long-term debt 52,355 69,999
Asset retirement obligation 12,113 12,332
Other long-term liabilities 1,007 290
Deferred taxes 4,523 —
98,005 117,695
SHAREHOLDERS' EQUITY
Share capital 152,084 152,084
Accumulated other comprehensive income (loss) (939 ) 2,793
Contributed surplus 24,195 23,329
Retained earnings 44,951 31,801
220,291 210,007
$ 318,296 $ 327,702
Consolidated Statements of Changes in Shareholders' Equity
(Expressed in thousands of US Dollars)
Years Ended December 31
2018 2017
Share Capital
Balance, beginning of year $ 152,084 $ 152,084
Balance, end of year $ 152,084 $ 152,084
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year $ 2,793 $ —
Currency translation adjustment (3,732 ) 2,793
Balance, end of year $ (939 ) $ 2,793
Contributed Surplus
Balance, beginning of year $ 23,329 $ 22,695
Share-based compensation expense 866 634
Balance, end of year $ 24,195 $ 23,329
Retained Earnings
Balance, beginning of year $ 31,801 $ 110,537
Net earnings (loss) 15,677 (78,736 )
Dividends $ (2,527 ) $ —
Balance, end of year $ 44,951 $ 31,801
Consolidated Statements of Cash Flows
(Expressed in thousands of US Dollars)
Years Ended December 31
2018 2017
CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:
OPERATING
Net earnings (loss) $ 15,677 $ (78,736 )
Adjustments for:
Depletion, depreciation and amortization 34,291 40,036
Asset retirement obligation accretion 270 256
Deferred lease inducement (90 ) (91 )
Impairment loss 14,500 79,025
Stock-based compensation 3,536 1,478
Finance costs 5,075 6,233
Unrealized (gain) loss on financial instruments (9,335 ) 8,121
Unrealized loss on foreign currency translation (135 ) (35 )
Gain on asset dispositions (207 ) —
Asset retirement obligations settled (300 ) (695 )
Changes in non-cash working capital 5,910 3,858
Net cash generated by operating activities 69,192 59,450
INVESTING
Additions to intangible exploration and evaluation assets (9,288 ) (16,905 )
Additions to petroleum and natural gas assets (30,832 ) (20,301 )
Additions to other assets (586 ) (953 )
Proceeds from asset dispositions 207 —
Changes in restricted cash — 18,323
Changes in non-cash working capital 251 (1,587 )
Net cash used in investing activities (40,248 ) (21,423 )
FINANCING
Interest paid (4,767 ) (8,506 )
Increases in long-term debt 508 85,328
Repayment of convertible debentures — (73,375 )
Repayments of long-term debt (17,797 ) (26,041 )
Dividends paid (2,527 ) —
Changes in non-cash working capital (3 ) —
Net cash used in financing activities (24,586 ) (22,594 )
Currency translation differences relating to cash and cash equivalents (102 ) 548
NET INCREASE IN CASH AND CASH EQUIVALENTS 4,256 15,981
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 47,449 31,468
CASH AND CASH EQUIVALENTS, END OF YEAR $ 51,705 $ 47,449
MANAGEMENT STRATEGY AND OUTLOOK
The 2019 outlook provides information as to management's expectation for results of operations for 2019. Readers are cautioned that the 2019 outlook may not be appropriate for other purposes. The Company's expected results are sensitive to fluctuations in the business environment, including disruptions caused by the ongoing political changes and civil unrest occurring in the jurisdictions that the Company operates in, and may vary accordingly. This outlook contains forward-looking statements that should be read in conjunction with the Company's disclosure under 'Forward-Looking Statements', outlined on the first page of this Management's Discussion & Analysis ("MD & A").
2019 Outlook
The 2019 production outlook for the Company is provided as a range to reflect timing and performance contingencies.
Total corporate production is expected to range between 14,000 and 15,000 boe/d for 2019 (mid-point of 14,500 boe/d) with a 94% weighting to oil and liquids. Egypt oil production is expected to range between 11,600 and 12,400 bbls/d in 2019. Canadian production was expected to range between 2,400 and 2,600 boe/d in 2019, which included approximately 300 boe/d of ethane production, which is currently being sold as natural gas with increased energy content. A prolonged shut down of the third party deep cut extraction plant may impact the Canadian production boe/d guidance for 2019. The third party operated gas processer has shut down their deep cut ethane extraction plant due to low ethane prices and associated pipeline egress issues in Alberta. The reduction of ethane sales is expected to be generally revenue neutral due to the increased energy content of natural gas sales. The Canadian production range includes 12 months of production from the 2018 drilling program which was complete and ready for production in January of 2019.
Funds flow from operations in any given period will be dependent upon the timing of crude oil tanker liftings in Egypt and the market price of the crude oil sold. Because these factors are difficult to accurately predict, the Company has not provided funds flow from operations guidance for 2019. Funds flow from operations and inventory levels in Egypt may fluctuate significantly from quarter to quarter due to the timing of liftings.
The below chart provides a comparison of projected netbacks of a typical Cardium well compared to a similar well in Egypt under multiple price sensitivities.
Netback sensitivity
Benchmark crude oil price (US$/bbl) 40 50 60 70 80
Benchmark natural gas price (C$/mcf) 0.95 1.10 1.30 1.50 1.70
Netback ($/boe)
Egypt - crude oil1 2.62 6.85 11.08 15.32 19.55
Canada - crude oil2 17.63 25.17 32.20 39.43 46.61
Canada - natural gas and NGLs2 (1.25 ) (0.10 ) 0.87 2.64 4.39
1 Egypt assumptions: using anticipated 2019 Egypt production profile, Ras Gharib price differential estimate of $10.50 per bbl applied consistently at all price points, concession differentials of 4%/5%/3% applied to WG/WB/NWG respectively, operating costs estimated at ~$9.90/bbl, and maximum cost recovery resulting from accumulated cost pools.
2 Canada assumptions: using anticipated 2019 Canada production profile, Edmonton Light price differential estimate of $8.00 per bbl, Edmonton Light to Harmattan discount of C$2.50 per bbl, operating costs estimated at ~C$12.70/boe, NGL mixture price at 45% of Edmonton Light, and takes into consideration Canadian tax pools.
2019 Capital Budget
The Company's 2019 budgeted capital program of $34.1 million (before capitalized G & A) includes $24.1 million for Egypt and $10.0 million (C$13.0 million) for Canada. The 2019 plan was prepared to maximize free cash flow to direct at future value growth opportunities.
Egypt
The $24.1 million Egypt program has $7.0 million (30%) allocated to exploration and $17.1 million (70%) to development.
The $7.0 million 2019 exploration program includes 2 exploration wells in the Eastern Desert (1 well in West Bakr, 1 well in NW Gharib), an appraisal well and contingent early development capital at South Ghazalat. The West Bakr exploration well is in H block targeting a potential Asl A pool extension of the Rabul field which was discovered and placed on production in the adjacent GPC concession to the south. The NW Gharib exploration well is targeting an undrilled fault block north of the NWG 38A pool.
The $17.1 million 2019 development program is focused on the Eastern Desert which includes: 3 development wells in West Bakr (1 each in M, H and K pools) and 1 development well in the NW Gharib 38A pool, 10 recompletions in West Bakr, facility and water handling expansion at West Bakr and development/maintenance projects in the Eastern Desert (West Bakr, NW Gharib and West Gharib).
The primary focus of the 2019 Egypt plan is to sustain/grow Eastern Desert production and to evaluate the South Ghazalat exploration concession in the Western Desert. No additional production has been forecast from South Ghazalat pending approval of the SGZ 6X development plan. Additional investment in South Alamein is conditional on negotiating the necessary extensions following the military rejection of access to the SA 24 X exploration well surface location.
Canada
The $10.0 million (C$13.0 million) Canada program consists of 4 (4 net) horizontal (multi-stage frac) wells targeting the Cardium light oil resource at Harmattan and additional maintenance/development capital. The Cardium drilling program in 2019 consists of 3 development wells and 1 outpost well (deferred from the 2018 program) to evaluate the south Harmattan acreage acquired in 2018. The 2019 program is contingent on differentials for Western Canadian Edmonton light sweet oil prices remaining at economic levels.
The 2019 capital program is summarized in the following table:
TransGlobe 2019 Capital ($MM) Gross Well Count
Development Exploration Total Drilling
Concession Wells Other1 Wells Other1 Devel Explor Total
West Gharib — 2.7 — — 2.7 — — —
West Bakr 3.4 9.8 1.1 — 14.3 3 1 4
NW Gharib 1.0 0.3 1.0 — 2.3 1 1 2
South Alamein — — — 1.3 1.3 — — —
South Ghazalat — — 1.2 2.3 3.5 — 1 1
Egypt $4.4 $12.8 $3.3 $3.6 $24.1 4 3 7
Canada $6.3 $0.5 $3.2 — $10.0 3 1 4
2019 Total $10.7 $13.3 $6.5 $3.6 $34.1 7 4 11
Splits (%) 70% 30% 100% 64% 36% 100%
1 Other includes completions, workovers, recompletions and equipping.
Advisory on Forward-Looking Statements
Certain statements included in this news release constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "may", "will", "would" or similar words suggesting future outcomes or statements regarding an outlook.
In particular, forward-looking information and statements contained in this document include, but are not limited to, statements relating to "reserves" which are, by their nature, forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves or resources, as applicable, described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. The recovery and reserve estimates of TransGlobe's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. Many factors could cause TransGlobe's actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, TransGlobe.
Forward-looking information and statements contained in this document include the payment of dividends, including the timing and amount thereof, and the Company's intention to declare and pay dividends in the future under its current dividend policy. Without limitation of the foregoing, future dividend payments, if any, and the level thereof is uncertain, as the Company's dividend policy and the funds available for the payment of dividends from time to time will be dependent upon, among other things, free cash flow, financial requirements for the Company's operations and the execution of its strategy, ongoing production maintenance, growth through acquisitions, fluctuations in working capital and the timing and amount of capital expenditures and anticipated business development capital, payment irregularity in Egypt, debt service requirements and other factors beyond the Company's control. Further, the ability of the Company to pay dividends will be subject to applicable laws (including the satisfaction of the liquidity and solvency tests contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness.
In addition to other factors and assumptions which may be identified in this news release, assumptions have been made regarding, among other things, anticipated production volumes; the timing of drilling wells and mobilizing drilling rigs; the number of wells to be drilled; the Company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business; future capital expenditures to be made by the Company; future sources of funding for the Company's capital programs; geological and engineering estimates in respect of the Company's reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities; current commodity prices and royalty regimes; availability of skilled labour; future exchange rates; the price of oil; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; future operating costs; uninterrupted access to areas of TransGlobe's operations and infrastructure; recoverability of reserves and future production rates; that TransGlobe will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that TransGlobe's conduct and results of operations will be consistent with its expectations; that TransGlobe will have the ability to develop its properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of TransGlobe's reserves and resource volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; and other matters.
Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties which may cause actual results to differ materially from the forward-looking statements or information include, among other things, operating and/or drilling costs are higher than anticipated; unforeseen changes in the rate of production from TransGlobe's oil and gas properties; changes in price of crude oil and natural gas; adverse technical factors associated with exploration, development, production or transportation of TransGlobe's crude oil reserves; changes or disruptions in the political or fiscal regimes in TransGlobe's areas of activity; changes in tax, energy or other laws or regulations; changes in significant capital expenditures; delays or disruptions in production due to shortages of skilled manpower equipment or materials; economic fluctuations; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; obtaining required approvals of regulatory authorities; volatility in market prices for oil; fluctuations in foreign exchange or interest rates; environmental risks; ability to access sufficient capital from internal and external sources; failure of counterparties to perform under the terms of their contracts; and other factors beyond the Company's control. Readers are cautioned that the foregoing list of factors is not exhaustive. Please consult TransGlobe's public filings at www.sedar.com and www.sec.gov/edgar.shtml for further, more detailed information concerning these matters, including additional risks related to TransGlobe's business.
The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this news release are expressly qualified by this cautionary statement.
For further information, please contact:
Investor Relations Via FTI Consulting
Telephone: +1 (403) 264-9888
Email:
Web site: http://www.trans-globe.com
TransGlobe Energy www.trans-globe.com
Randy Neely, President & Chief Executive Officer
Eddie Ok, Vice President, Finance & Chief Financial Officer
Canaccord Genuity (Nomad & Joint Broker) +44 (0) 20 7523 8000
Henry Fitzgerald-O'Connor
James Asensio
GMP First Energy (Joint Broker) +44 (0) 207 448 0200
Jonathan Wright
FTI Consulting (Financial PR) +44 (0) 203 727 1000
Ben Brewerton
Genevieve Ryan
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