CALGARY, ALBERTA--(Marketwired - Nov. 10, 2015) - Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") (TSX:TVE) is pleased to announce its operating and financial results for the third quarter of 2015. Production in the third quarter of 2015 increased by 25% to 8,717 boe/d and funds flow from operations increased by 11% to $14.6 million from the second quarter of 2015 despite a 16% decrease in crude oil prices. As a result, Tamarack is increasing its 2015 average production guidance to 8,200-8,300 boe/d (approximately 55-60% oil & NGLs) from 8,000-8,200 boe/d (approximately 55-60% oil & NGLs) and its production exit rate to 9,500-9,700 boe/d (approximately 55-60% oil & NGLs) from 9,200-9,500 boe/d (approximately 55-60% oil & NGLs).
The Company has filed its unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2015 ("Financial Statements") and management's discussion and analysis ("MD&A") on SEDAR. Selected financial and operational information is outlined below and should be read in conjunction with the Financial Statements, which were prepared in accordance with International Financial Reporting Standards ("IFRS"), and the related MD&A. These documents are accessible on Tamarack's website at www.tamarackvalley.ca or on SEDAR at www.sedar.com.
Financial and Operating Highlights
- Delivered production of 8,717 boe/d (58% oil and NGLs), an increase of 51% compared to 5,765 boe/d (64% oil and NGLs) in Q3/2014, and delivered production of 7,935 boe/d (60% oil and NGLs) for the nine month period ended September 30, 2015, an increase of 57% compared to 5,056 boe/d for the same period of 2014 (61% oil and NGLs).
- Grew production per fully diluted share on a year over year basis by 7.3%.
- Funds from operations decreased by 8% to $14.6 million ($0.15/share) compared to $15.8 million ($0.26/share) in Q3/2014. Funds from operations decreased by 8% in the third quarter due to a 48% decrease in realized commodity prices on a boe basis, partially offset by the 51% increase in production.
- Realized $4.3 million ($5.35/boe) in hedging gains during the third quarter of 2015, bringing the year to date total gains to $10.0 million ($4.61/boe). Tamarack's hedging gains supported a first nine months of 2015 operating netback of $24.05/boe.
- General and Administrative ("G&A") expenses per boe decreased by 17% to $2.16/boe in Q3/2015 from $2.60/boe in Q2/2015 thanks to the 25% increase in production without the adding any incremental G&A expenses.
- As expected, operating costs increased by 13% in Q3/2015 to $14.05/boe from $12.43/boe, due to the higher cost asset purchased late in Q2/2015. Tamarack commenced an infrastructure optimization project in Q3 that is expected to be completed by the end of Q1/16, which should return operating costs to $12.00-$12.50/boe.
- Total capital expenditures for the quarter were $23.2 million compared to $196.3 million in Q3/2014 and $96.6 million compared to $262.1 million for the nine month periods ended September 30, 2015 and 2014, respectively.
- Reduced net debt to 1.8 times annualized Q3/15 funds from operations.
- Closed four minor tuck-in acquisitions in the Wilson Creek area, one in Q3/2015 and three in Q4/15, adding approximately 103 boe/d and 35.75 (3.64 net) sections of prospective lands for a total cost of $3,112,000.
- Maintained a disciplined hedging program with an average of over 2,500 bbl/d of oil production hedged at an average WTI fixed price of over $77.00/bbl (Canadian dollar equivalent) to the end of the second quarter of 2016.
- Semi-annual credit facility review is underway with no expected changes to the existing facility.
Operations Update
Tamarack's average daily production of 8,717 boe/d (58% oil & NGLs) during the third quarter of 2015 exceeded internal guidance of 8,300 to 8,500 boe/d, despite experiencing higher than expected downtime on various TransCanada ("TCPL") pipelines during the quarter, which resulted in approximately 387 boe/d of lost production to the quarter average. The Company was able to exceed production targets due to performance in the Wilson Creek area of Alberta and the Hatton area of Saskatchewan. The Company is expected to experience similar TCPL curtailments and intermittent shut-ins during the fourth quarter of 2015 as it experienced during the third quarter.
During the third quarter of 2015, the Company brought on production 8 (7.6 net) Cardium oil wells and expects to bring on another 7 (5.3 net) Cardium oil wells late in the fourth quarter that have already been drilled. The Company also began debottlenecking infrastructure in the recently acquired property in Wilson Creek in order to optimize operations by increasing capacity and by reducing operating costs. This project will be ongoing throughout the rest of this year and is on track to be completed by the end of the first quarter of 2016. The Company expects this project will result in a reduction of $1.00-$1.50/boe in operating costs. Tamarack plans to drill another 3 (2.9 net) Cardium wells during the fourth quarter that would be expected to come on production early in the first quarter of 2016.
Sustainable Cash Flow
Tamarack's superior drilling inventory generates sustainable cash flow at a wide range of commodity prices. During 2015, the Company has continued to increase operational efficiencies as a result of tuck-in acquisitions, reduced capital costs and increased capital efficiencies in an attempt to reduce the effects of significantly lower commodity prices than realized in 2014. This initiative has allowed the Company to continue to drill wells in the Wilson Creek area which are achieving 1.5 year payouts or less at current strip prices. Tamarack has taken the necessary measures to be sustainable in 2016 at current strip prices by maintaining production at or above 9,500 boe/d while limiting capital expenditures to funds from operations. The Company estimates it has approximately four years of drilling inventory at sub $55/bbl WTI oil pricing and approximately six years of inventory at oil pricing between $55 and $75 WTI.
Tamarack expects to announce its 2016 capital budget and production guidance by January 22, 2016.
Financial & Operating Results
| |
|
|
Three months ended |
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Nine months ended |
|
| |
|
|
September 30, |
|
September 30, |
|
| |
2015 |
|
2014 |
|
% change |
|
2015 |
|
2014 |
|
% change |
|
| ($, except share numbers) |
|
|
|
|
|
|
|
|
|
|
|
|
| Total Revenue |
27,779,319 |
|
35,333,256 |
|
(21 |
) |
78,420,495 |
|
92,153,776 |
|
(15 |
) |
| Funds from operations 1 |
14,618,184 |
|
15,808,881 |
|
(8 |
) |
41,546,600 |
|
47,043,666 |
|
(12 |
) |
| |
Per share - basic 1 |
$ 0.15 |
|
$ 0.26 |
|
(42 |
) |
$ 0.47 |
|
$ 0.81 |
|
(42 |
) |
| |
Per share - diluted 1 |
$ 0.15 |
|
$ 0.25 |
|
(40 |
) |
$ 0.47 |
|
$ 0.79 |
|
(41 |
) |
| Net income (loss) |
(15,063,870 |
) |
6,790,587 |
|
(322 |
) |
(22,447,287 |
) |
13,823,840 |
|
(262 |
) |
| |
Per share - basic |
$ (0.15 |
) |
$ 0.11 |
|
(236 |
) |
$ (0.26 |
) |
$ 0.24 |
|
(208 |
) |
| |
Per share - diluted |
$ (0.15 |
) |
$ 0.11 |
|
(236 |
) |
$ (0.26 |
) |
$ 0.23 |
|
(213 |
) |
| Net debt 2 |
(105,837,205 |
) |
121,684,316 |
|
(187 |
) |
(105,837,205 |
) |
121,684,316 |
|
(187 |
) |
| Capital Expenditures 3 |
23,165,628 |
|
196,374,750 |
|
(88 |
) |
96,613,691 |
|
262,129,065 |
|
(63 |
) |
| Weighted average shares outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic |
99,933,725 |
|
61,423,738 |
|
63 |
|
87,532,408 |
|
58,140,697 |
|
51 |
|
| |
Diluted |
99,933,725 |
|
63,509,567 |
|
57 |
|
87,532,408 |
|
59,872,353 |
|
46 |
|
| Share Trading |
|
|
|
|
|
|
|
|
|
|
|
|
| High |
$ 3.58 |
|
$ 7.85 |
|
(54 |
) |
$ 4.80 |
|
$ 7.85 |
|
(39 |
) |
| Low |
$ 1.83 |
|
$ 5.64 |
|
(68 |
) |
$ 1.83 |
|
$ 3.59 |
|
(49 |
) |
| Trading volume |
23,956,012 |
|
36,033,440 |
|
(34 |
) |
67,394,527 |
|
106,789,947 |
|
(37 |
) |
| Average daily production |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Light oil (bbls/d) |
3,499 |
|
3,040 |
|
15 |
|
3,517 |
|
2,649 |
|
33 |
|
| |
|
Heavy oil (bbls/d) |
660 |
|
346 |
|
91 |
|
595 |
|
204 |
|
192 |
|
| |
|
NGLs (bbls/d) |
890 |
|
302 |
|
195 |
|
663 |
|
225 |
|
195 |
|
| |
|
Natural gas (mcf/d) |
22,005 |
|
12,462 |
|
77 |
|
18,962 |
|
11,868 |
|
60 |
|
| |
|
Total (boe/d) |
8,717 |
|
5,765 |
|
51 |
|
7,935 |
|
5,056 |
|
57 |
|
| Average sale prices |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Light oil ($/bbl) |
54.39 |
|
95.83 |
|
(43 |
) |
54.06 |
|
96.62 |
|
(44 |
) |
| |
|
Heavy oil ($/bbl) |
49.15 |
|
77.59 |
|
(37 |
) |
47.31 |
|
77.59 |
|
(39 |
) |
| |
|
NGLs ($/bbl) |
13.78 |
|
47.74 |
|
(71 |
) |
20.28 |
|
57.28 |
|
(65 |
) |
| |
|
Natural gas ($/mcf) |
3.04 |
|
4.13 |
|
(26 |
) |
2.93 |
|
4.46 |
|
(34 |
) |
| |
|
Total ($/boe) |
34.64 |
|
66.62 |
|
(48 |
) |
36.20 |
|
66.77 |
|
(46 |
) |
| Operating netback ($/Boe) 4 |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average realized sales |
34.64 |
|
66.62 |
|
(48 |
) |
36.20 |
|
66.77 |
|
(46 |
) |
| |
Royalty expenses |
(3.81 |
) |
(8.87 |
) |
(57 |
) |
(3.69 |
) |
(8.60 |
) |
(57 |
) |
| |
Production expenses |
(14.05 |
) |
(14.84 |
) |
(5 |
) |
(13.07 |
) |
(14.24 |
) |
(8 |
) |
| Operating field netback ($/Boe) 4 |
16.78 |
|
42.91 |
|
(61 |
) |
19.44 |
|
43.93 |
|
(56 |
) |
| |
Realized commodity hedging gain (loss) |
5.35 |
|
(2.03 |
) |
364 |
|
4.61 |
|
(2.95 |
) |
(256 |
) |
| |
Operating netback |
22.13 |
|
40.88 |
|
(46 |
) |
24.05 |
|
40.98 |
|
(41 |
) |
| Funds flow from operations netback ($/Boe) 4 |
18.23 |
|
29.81 |
|
(39 |
) |
19.18 |
|
34.08 |
|
(44 |
) |
Notes:
| (1) |
Funds from operations is calculated as cash flow from operating activities before the change in non-cash working capital and abandonment. |
| (2) |
Net debt does not have any standard meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. Net debt includes accounts receivable, prepaid expenses and deposits, bank debt and accounts payable and accrued liabilities, but excludes the fair value of financial instruments. |
| (3) |
Capital expenditures include property acquisitions and are presented net of disposals, but exclude corporate acquisitions. |
| (4) |
Operating netback, operating field netback and funds flow from operations netback does not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. Operating field netback equals total petroleum and natural gas sales less royalties and operating costs calculated on a boe basis. Operating netback is the operating field netback less realized gains and losses on commodity derivative contracts. Funds flow from operations netback equals funds flow from operations divided by the total sales volume and reported on a per boe basis. Tamarack considers operating netback and funds flow from operations netback as important measures to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices. |
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to long-term growth and the identification, evaluation and operation of resource plays in the Western Canadian Sedimentary Basin. Tamarack's strategic direction is focused on two key principles - targeting resource plays that provide long-life reserves, and using a rigorous, proven modeling process to carefully manage risk and identify opportunities. The Company has an extensive inventory of low-risk development oil locations in the Pembina, Wilson Creek, Garrington and Lochend Cardium fairway and the Redwater shallow Viking play in Alberta. With a balanced portfolio and an experienced and committed management team, Tamarack intends to continue to deliver on its promise to maximize shareholder return while managing its balance sheet.
Abbreviations
| bbls |
barrels |
| bbls/d |
barrels per day |
| boe |
barrels of oil equivalent |
| boe/d |
barrels of oil equivalent per day |
| Mboe |
thousands of barrels of oil equivalent |
| mcf |
thousand cubic feet |
| MMcf |
million cubic feet |
| MMbbls |
million barrels |
| mcf/d |
thousand cubic feet per day |
Unit Cost Calculation
For the purpose of calculating unit costs, natural gas volumes have been converted to a barrel of oil equivalent ("boe") using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with Canadian Securities Regulators' NI 51-101. Boe may be misleading, particularly if used in isolation.
Forward Looking Information
This press release contains certain forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as "target", "plan", "continue", "intend", "estimate", "expect", "may", "will", "should", or similar words suggesting future outcomes. More particularly, this press release contains statements concerning expected TCPL curtailments and intermittent shut-ins during the fourth quarter of 2015, estimated 2015 annual production, a reduction in operating costs resulting from an optimization debottlenecking project, timing of completion of the debottlenecking infrastructure, the outcome of a semi-annual credit facility, expected drilling plans and estimated drilling inventory. The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack relating to prevailing commodity prices, the availability and costs of drilling rigs, other oilfield services and third party facilities, the timing of past operations and activities in the planned areas of focus, the drilling, completion and tie-in of wells being completed as planned, the performance of new and existing wells, the application of existing drilling and fracturing techniques, the continued availability of capital and skilled personnel, the ability to maintain or grow the banking facilities and the accuracy of Tamarack's geological interpretation of its drilling and land opportunities. Although management considers these assumptions to be reasonable based on information currently available to it, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct.
By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures); commodity prices; the uncertainty of estimates and projections relating to production, cash generation, costs and expenses; health, safety, litigation and environmental risks; and access to capital. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to react to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to Tamarack's annual information form (AIF) for additional risk factors relating to Tamarack. The AIF is available for viewing under the Company's profile on www.sedar.com.
The forward-looking statements contained in this press release are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.