Tourmaline adds 338 mmboe of reserves in 2018, 2P reserves increased to 2.46 billion boe

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CALGARY, Feb. 20, 2019 /CNW/ – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) is pleased to report very strong total reserve growth, liquids reserve growth and a continued reserve value increase in the current depressed natural gas price environment. The Company executed on the 2017-2018 plan to concentrate almost entirely on internal EP growth and has produced the best reserve metrics in the Company’s 10 year history over the past two years.

RESERVE HIGHLIGHTS

Proved plus probable reserves (“2P”) increased by 241.2 mmboe to 2.46 billion boe during 2018, an 11% increase over 2017 year-end reserves of 2.22 billion boe and a 15% increase of 337.9 mmboe which includes annual production of 96.7 million boe. Total proved (“TP”) reserves increased 23% to 1.21 billion boe and proved, developed producing (“PDP”) reserves of 473.3 mmboe increased 31% over year-end 2017 when including 2018 annual production.
After ten years of operation, Tourmaline has 2P natural gas reserves of 11.7 tcf and 2P liquid reserves of 505.2 mmboe of oil, condensate and liquids (December 31, 2018). The Company has the largest publicly-reported, independently-assessed, 2P natural gas reserves in Canada.
2P reserve net present value (“NPV”)⁽¹⁾ of $58.57 per diluted share, TP reserve NPV of $33.67 per diluted share and a PDP reserve NPV of $17.36 per diluted share at December 31, 2018. The Company was able to continue to grow reserve NPV per diluted share in 2018 despite significantly lower natural gas pricing used in the independent reserve report.
2P finding, development and acquisition costs (“FD&A”) in 2018 were $5.15/boe including changes in future development capital (“FDC”) ($3.59/boe excluding change in FDC) based on total capital expenditures of $1.214 billion; TP FD&A in 2018 were $6.79/boe including change in FDC ($4.91/boe excluding change in FDC). 2018 PDP FD&A were $9.11/boe.
The 2018 2P recycle ratio was 2.6 based on 2P FD&A of $5.15/boe (including FDC), and 2018 estimated cash flow⁽²⁾ of $13.47/boe. The 2018 TP recycle ratio was 2.0 and the 2018 PDP recycle ratio was 1.5.
2P reserve replacement ratio⁽³⁾ of 3.5 times based on 2P reserve additions of 337.9 mmboe before 2018 production of 96.7 mmboe.
Tourmaline systematically converts TP and 2P reserves to PDP reserves; 145 wells (gross) of the 239 wells (gross) rig released in 2018 converted pre-existing TP/2P reserves to PDP reserves. The FDC in the 2018 2P reserve category represents approximately 4.5 years of future-projected Company cash flow.
For the sixth year in a row the Company realized net positive technical revisions to previously booked reserves.

Consistent Value Growth and Industry-Leading Efficiencies

	PDP FD&A ($/boe)	1P FD&A ($/boe)		2P FD&A ($/boe)		2P PV10 Annual Reserve Value Growth
		Excl FDC	Incl FDC	Excl FDC	Incl FDC
2018	9.11	4.91	6.79	3.59	5.15	$832.8 MM
2015-2017 (Avg)	11.94	7.06	8.12	3.58	5.16	$2.48 B

PRODUCTION HIGHLIGHTS

Full-year 2018 average production of 265,044 boepd was 9% higher than 2017 average production of 242,325 boepd and within the guidance range.
Q4 2018 liquids production (oil, condensate, NGL) of 51,938 bpd was 14% higher than Q4 2017 average liquids production. Tourmaline is forecasting 2019 average liquids production of 66,000 bpd, representing 39% year-over-year growth, forecast to be amongst the highest liquids growth rates in the industry this year.
In 2018, Tourmaline’s EP capital program of $1.23 billion generated approximately 110 mboepd of new production resulting in a 2018 capital efficiency of $11,200 boepd.
Q4 2018 average production of 276,568 boepd was 9% higher than Q3 2018 average production of 254,185 boepd.
Tourmaline has been producing at the 1H 2019 guidance range of 290,000 – 300,000 boepd during the first quarter; the Company will bring on the 50,000 boepd Gundy deep cut facility during June.

FINANCIAL HIGHLIGHTS

Full-year 2018 EP capital spending was $1.23 billion. Q4 2018 cash flow was $391.5 million and Q4 EP capital spending was $363.2 million. Tourmaline’s low cash costs and industry-leading capital execution costs allow the Company to achieve cash flow per share growth, generate free cash flow, and pay a dividend.
The Company completed a small acquisition in the Peace River High Triassic oil complex for $21.2 millionduring the fourth quarter of 2018, consolidating acreage in the core Upper Charlie Lake pool at Spirit Riverproper.
The 2018 EP capital program included approximately $110.0 million for the Gundy deep cut gas plant, the benefit of which will be realized in 2H 2019.
The 2019 EP capital program is anticipated to be $1.225 billion⁽⁴⁾, reflecting the $75.0 million reduction announced on January 15, 2019. Full-year production guidance remains unchanged at 300,000 boepd.
1H 2019 EP capital spending of $600 million is planned compared to forecast 1H 2019 cash flow of $700 – $750 million.
The Company expects to sell $20.0 – $25.0 million of non-core, non-producing assets during the first half of 2019.
Tourmaline has secured multiple long-term liquid processing and handling agreements in BC and Alberta to allow for premium pricing for the Company’s future liquid streams, including the large volumes at Gundy in BC.

EP UPDATE

Tourmaline is currently operating a total of 13 drilling rigs across the three core EP complexes, with the rig count dropping to six during spring break-up.
The Company’s initial delineation well at Attachie, where the Company has 29,000 undeveloped acres, tested at 767 boepd at the end of a 157 hour test (200 bpd oil and 3.4 mmcfpd of sweet natural gas). At least one follow-up appraisal well is planned for 2H 2019, where the Company has a large number of future drilling locations on the existing land block.
The most recent Cardium horizontal in the Company’s frontal foothills overthrust play along the western margin of the Deep Basin was flowing at 21.5 mmcfpd of natural gas with 979 bbls/d of condensate after 70 hours on-stream. Six of the eight wells drilled on this Cardium play are tier 1 locations with estimated EUR ranging between 12-15 bcf of gas and 225-400 mstb of condensate plus liquids per well (ref. GLJ/Deloitte). The Company plans further delineation wells along the 225 km play trend during the balance of 2019.

______________________________

(1)	Reserve NPV per share is calculated as the before tax net present value of the reserves at December 31, 2018 discounted at 10% divided by total diluted shares outstanding at December 31, 2018.
(2)	Cash flow is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” in this release for additional information. All financial information is unaudited. See unaudited financial information section in this release.
(3)	Reserve replacement ratio is calculated by dividing the annual 2P reserve additions (including annual production) by annual production.
(4)	The capital reduction has not been reflected in the Company’s current formal guidance. The Company intends to update formal guidance, including these capital reductions, along with the year-end financial results in March 2019.

2018 RESERVE SUMMARY

The following tables summarize the Company’s gross reserves defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. Company net reserves are defined as the working net carried and royalty interest reserves after deduction of all applicable burdens.

Reserves and Future Net Revenue Data (Forecast Prices and Costs)

	Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2018 Forecast Prices and Costs⁽¹⁾
		Light & Medium Crude Oil		Conventional Natural Gas		Shale Natural Gas⁽²⁾		Natural Gas Liquids		Total Oil Equivalent

Reserves Category		Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (MMcf)	Company Net (MMcf)	Company Gross (MMcf)	Company Net (MMcf)	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (Mboe)	Company Net (Mboe)
Proved Producing		12,776	10,695	1,647,883	1,522,885	718,631	700,727	66,075	56,622	473,269	437,919
Proved Developed Non-Producing		1,842	1,511	93,816	86,327	189,425	187,149	12,455	11,135	61,504	58,225
Proved Undeveloped		25,008	20,897	1,927,661	1,802,825	1,310,008	1,254,523	106,988	97,913	671,607	628,368
Total Proved Reserves		39,626	33,103	3,669,359	3,412,037	2,218,064	2,142,398	185,518	165,670	1,206,381	1,124,512
Total Probable Reserves		42,421	34,475	2,402,017	2,202,990	3,423,238	3,114,362	237,681	205,613	1,250,977	1,126,313
Total Proved Plus Probable Reserves		82,046	67,578	6,071,376	5,615,028	5,641,302	5,256,760	423,198	371,283	2,457,358	2,250,826

Reserves Category	Net Present Values Of Future Net Revenue ($000s)
	Before Future Income Taxes Discounted at (%/year)					After Income Taxes Discounted at⁽³⁾ (%/year)					Unit Value Before Income Tax Discounted at 10%/year
	0	5	10	15	20	0	5	10	15	20	($/Boe)	($/Mcfe)
Proved Producing	7,240,410	5,717,521	4,721,579	4,036,357	3,541,211	7,114,318	5,656,857	4,691,064	4,020,391	3,532,559	10.78	1.80
Proved Developed Non-Producing	1,028,081	762,593	601,144	495,218	421,209	753,006	598,008	498,946	429,756	378,150	10.32	1.72
Proved Undeveloped	8,822,179	5,638,372	3,838,123	2,730,228	2,000,951	6,469,863	4,075,075	2,723,454	1,895,281	1,352,929	6.11	1.02
Total Proved Reserves	17,090,670	12,118,486	9,160,845	7,261,803	5,963,372	14,337,187	10,329,941	7,913,463	6,345,428	5,263,638	8.15	1.36
Total Probable Reserves	21,980,983	11,338,472	6,772,624	4,457,988	3,135,558	16,081,110	8,219,331	4,847,751	3,146,492	2,181,518	6.01	1.00
Total Proved Plus Probable Reserves	39,071,654	23,456,959	15,933,470	11,719,791	9,098,929	30,418,297	18,549,272	12,761,214	9,491,920	7,445,156	7.08	1.18


Notes:

⁽¹⁾	Tables may not add due to rounding.

⁽²⁾	Shale Natural Gas is required to be presented separately from Conventional Natural Gas as its own product type pursuant to National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). While the Tourmaline Montney reserves do not strictly fit the definition of “shale gas” as defined in NI 51-101 because the natural gas is not “primarily adsorbed” as stated within the definition, the Montney reserves have been included as shale gas for purposes of this disclosure.

⁽³⁾	The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the value at the Company level which may be significantly different. The Company’s financial statements and management’s discussion and analysis should be consulted for information at the Company level.

	Total Future Net Revenue ($000s) (Undiscounted) as of December 31, 2018 Forecast Prices and Costs⁽¹⁾
Reserves Category		Revenue	Royalties	Operating Costs	Capital Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes ⁽²⁾
Proved Producing		11,832,962	981,507	3,366,201	4,000	240,845	7,240,410	126,092	7,114,318
Proved Developed Non-Producing		1,616,557	125,184	387,629	55,012	20,650	1,028,081	275,075	753,006
Proved Undeveloped		17,752,646	1,347,202	3,500,253	3,905,987	177,026	8,822,179	2,352,316	6,469,863
Total Proved		31,202,165	2,453,892	7,254,083	3,964,999	438,520	17,090,670	2,753,483	14,337,187
Total Probable		39,628,699	4,567,376	9,127,569	3,657,044	295,726	21,980,983	5,899,874	16,081,110
Total Proved Plus Probable		70,830,864	7,021,268	16,381,652	7,622,043	734,246	39,071,654	8,653,357	30,418,297


Notes:

⁽¹⁾	Table may not add due to rounding.

⁽²⁾	The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the value at the Company level which may be significantly different. The Company’s financial statements and management’s discussion and analysis should be consulted for information at the Company level.

	Summary of Pricing and Inflation Rate Assumptions Forecast Prices and Costs ⁽¹⁾

Year		Crude Oil and Natural Gas Liquids Pricing
			NYMEX WTI Near Month Futures Contract Crude Oil at Cushing, Oklahoma			Alberta Natural Gas Liquids (Then Current Dollars)
	Inflation%⁽²⁾	CAD/USD Exchange Rate $US/$Cdn⁽³⁾	Constant 2019 $ $US/Bbl	Then Current $US/Bbl	MSW, Light Crude Oil (40 API, 0.3%S) at Edmonton Then Current $Cdn/Bbl	Spec Ethane $Cdn/Bbl	Edmonton Propane $Cdn/Bbl	Edmonton Butane $Cdn/Bbl	Edmonton C5+ Stream Quality $Cdn/Bbl
2019	0.0	0.7567	58.58	58.58	67.30	6.82	26.13	27.32	70.10
2020	2.0	0.7817	63.33	64.60	75.84	8.40	31.27	41.10	79.21
2021	2.0	0.7967	65.55	68.20	80.17	9.98	34.58	49.28	83.33
2022	2.0	0.8033	66.90	71.00	83.22	11.22	37.25	55.65	86.20
2023	2.0	0.8067	67.27	72.81	85.34	11.89	38.73	57.92	88.16
2024	2.0	0.8083	67.56	74.59	87.33	12.22	39.75	59.27	90.20
2025	2.0	0.8083	67.86	76.42	89.50	12.45	40.76	60.77	92.43
2026	2.0	0.8083	68.25	78.40	91.89	12.71	41.93	62.37	94.87
2027	2.0	0.8083	68.27	79.98	93.76	12.96	42.84	63.65	96.80
2028	2.0	0.8083	68.27	81.59	95.68	13.28	43.80	64.97	98.79
2029	2.0	0.8083	68.27	83.22	97.57	13.53	44.73	66.26	100.76
2030	2.0	0.8083	68.26	84.87	99.52	13.85	45.64	67.56	102.77
2031	2.0	0.8083	68.26	86.57	101.52	14.10	46.56	68.92	104.84
2032	2.0	0.8083	68.26	88.30	103.55	14.36	47.46	70.33	106.94
2033	2.0	0.8083	68.27	90.08	105.65	14.68	48.44	71.72	109.10
2034	2.0	0.8083	68.27	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr

Year	Natural Gas and Sulphur Pricing
		Henry Hub Nymex Near Month Contract				Alberta Plant Gate				British Columbia
		Henry Hub Nymex Near Month Contract		Midwest Price @ Chicago Then Current $US/ MMbtu		Spot
		Constant 2019 $ $US/ MMbtu	Then Current $US/MMbtu	Midwest Price @ Chicago Then Current $US/ MMbtu	AECO/NIT Spot Then Current $Cdn/ MMbtu	Constant 2019 $ $Cdn/ MMbtu	Then Current $Cdn/MMbtu	ARP $Cdn/ MMbtu	Sumas Spot $US/ MMbtu	Westcoast Station 2 $Cdn/MMbtu	Spot Plant Gate $Cdn/MMbtu
2019		3.00	3.00	2.91	1.88	1.67	1.67	1.67	2.47	1.42	1.24
2020		3.07	3.13	3.04	2.31	2.06	2.10	2.10	2.59	1.94	1.75
2021		3.20	3.33	3.24	2.74	2.42	2.52	2.52	2.88	2.41	2.22
2022		3.30	3.51	3.41	3.05	2.66	2.83	2.83	3.09	2.76	2.56
2023		3.35	3.62	3.53	3.21	2.76	2.99	2.99	3.20	2.93	2.74
2024		3.35	3.70	3.61	3.31	2.79	3.08	3.08	3.28	3.06	2.86
2025		3.35	3.77	3.68	3.39	2.80	3.15	3.15	3.35	3.12	2.91
2026		3.35	3.85	3.76	3.46	2.80	3.22	3.22	3.43	3.19	2.98
2027		3.35	3.92	3.83	3.54	2.81	3.29	3.29	3.50	3.26	3.06
2028		3.35	4.01	3.91	3.62	2.83	3.38	3.38	3.59	3.35	3.14
2029		3.34	4.08	3.98	3.70	2.82	3.44	3.44	3.65	3.42	3.21
2030		3.35	4.16	4.07	3.78	2.83	3.52	3.52	3.73	3.51	3.28
2031		3.35	4.25	4.16	3.85	2.83	3.58	3.58	3.82	3.57	3.34
2032		3.34	4.33	4.23	3.92	2.82	3.65	3.65	3.89	3.63	3.40
2033		3.35	4.42	4.32	4.00	2.83	3.73	3.73	3.97	3.72	3.48
2034		3.35	+2.0%/yr	+2.0%/yr	+2.0%/yr	2.83	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr

Notes:

⁽¹⁾	Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ in the GLJ Reserve Report and Deloitte in the Deloitte Reserve Report, were an average of forecast prices and costs published by GLJ, Sproule Associates Ltd. and McDaniel & Associates Consultants Ltd. effective January 1, 2019 (each of which is available on their respective websites at www.gljpc.com, www.sproule.com and www.mcdan.com). GLJ assigns a value to the Company’s existing physical diversification contracts for natural gas for consuming markets at Dawn, Chicago, Ventura, Malin and PG&E based upon GLJ’s forecasted differential to NYMEX Henry Hub, contracted volumes, and transportation costs. No incremental value is assigned to potential future contracts which were not in place as of December 31, 2018.

⁽²⁾	Inflation rates used for forecasting prices and costs.

⁽³⁾	Exchange rates used to generate the benchmark reference prices in this table.

Reserves Performance Ratios

The following tables highlight Tourmaline’s reserves, F&D and FD&A costs as well as the associated recycle ratios.

Reserves, Capital Expenditures⁽²⁾ and Cash Flow⁽¹⁾⁽²⁾

As at December 31,	2018	2017	2016
*Reserves (Mboe)*
Proved Producing	473,269	436,208	351,931
Total Proved	1,206,381	1,055,702	858,932
Proved Plus Probable	2,457,358	2,216,206	1,746,822
*Capital Expenditures* ($ millions)
Exploration and Development⁽³⁾	1,261	1,364	756
Net Acquisitions (Dispositions)	(47)	58	1,545
Total Capital Expenditures	1,214	1,422	2,301
*Cash Flow* ($/boe)
Cash Flow	13.47	13.63	10.77
Cash Flow – Three Year Average	12.80	13.11	15.17


Notes:
⁽¹⁾	Cash flow is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” below and in the Company’s most recently filed Management’s Discussion and Analysis for further discussion.
⁽²⁾	2018 Financial numbers are unaudited.
⁽³⁾	Includes unaudited capitalized G&A of $30 million, $27 million and $25 million for 2018, 2017 and 2016 respectively.

Finding and Development Costs

Finding and Development Costs, Excluding FDC	2018	2017	2016	3-Year Avg.
*Total Proved*
Reserve Additions (MMboe)	241.0	272.8	126.4
F&D Costs ($/boe)	5.24	5.00	5.98	5.28
F&D Recycle Ratio⁽¹⁾	2.6	2.7	1.8	2.4
*Total Proved Plus Probable*
Reserve Additions (MMboe)	326.6	537.5	158.7
F&D Costs ($/boe)	3.86	2.54	4.76	3.31
F&D Recycle Ratio⁽¹⁾	3.5	5.4	2.3	3.9

Finding and Development Costs, Including FDC	2018	2017	2016	3-Year Avg.
*Total Proved*
Change in FDC ($ millions)	441.7	481.1	(239.9)
Reserve Additions (MMboe)	241.0	272.8	126.4
F&D Costs ($/boe)	7.07	6.76	4.08	6.35
F&D Recycle Ratio⁽¹⁾	1.9	2.0	2.6	2.0
*Total Proved Plus Probable*
Change in FDC ($ millions)	486.3	612.1	(518.6)
Reserve Additions (MMboe)	326.6	537.5	158.7
F&D Costs ($/boe)	5.35	3.68	1.49	3.87
F&D Recycle Ratio⁽¹⁾	2.5	3.7	7.2	3.3

Finding, Development and Acquisition Costs

Finding, Development and Acquisition Costs, Excluding FDC	2018	2017	2016	3-Year Avg.
*Total Proved*
Reserve Additions (MMboe)	247.4	285.2	282.8
FD&A Costs ($/boe)	4.91	4.98	8.14	6.05
FD&A Recycle Ratio⁽¹⁾	2.7	2.7	1.3	2.1
*Total Proved Plus Probable*
Reserve Additions (MMboe)	337.9	557.8	706.5
FD&A Costs ($/boe)	3.59	2.55	3.26	3.08
FD&A Recycle Ratio⁽¹⁾	3.7	5.3	3.3	4.2

Finding, Development and Acquisition Costs, Including FDC	2018	2017	2016	3-Year Avg.
*Total Proved*
Change in FDC ($ millions)	465.3	515.7	304.0
Reserve Additions (MMboe)	247.4	285.2	282.8
FD&A Costs ($/boe)	6.79	6.79	9.21	7.63
FD&A Recycle Ratio⁽¹⁾	2.0	2.0	1.2	1.7
*Total Proved Plus Probable*
Change in FDC ($ millions)	526.8	678.3	1,894.0
Reserve Additions (MMboe)	337.9	557.8	706.5
FD&A Costs ($/boe)	5.15	3.76	5.94	5.02
FD&A Recycle Ratio⁽¹⁾	2.6	3.6	1.8	2.6

Note:
⁽¹⁾	The recycle ratio is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year.

INVESTOR RELATIONS ACTIVITIES

Tourmaline is scheduled to press release full-year 2018 financial results after the close of markets on March 5, 2019. Conference call to be held on March 6, 2019 at 9:00 a.m. Details can be found on Tourmaline’s website at www.tourmalineoil.com.