Touchstone Announces 2016 Reserves

CALGARY, ALBERTA--(Marketwired - March 20, 2017) - Touchstone Exploration Inc. ("Touchstone" or the "Company") (TSX:TXP) announces the results of the independent December 31, 2016 reserve evaluation (the "Reserves Report") with respect to the Company's crude oil reserves in the Republic of Trinidad and Tobago ("Trinidad"). Amounts herein are in Canadian dollars unless otherwise stated.

Touchstone's year-end reserves were evaluated by independent reserves evaluator GLJ Petroleum Consultants Ltd. ("GLJ") in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional reserves information as required under NI 51-101 will be included in the Company's Annual Information Form which will be filed on SEDAR on or before March 31, 2017. The reserves estimates set forth below are based upon GLJ's Reserve Report dated March 17, 2017. All values in this press release are based on GLJ's forecast prices and estimates of future operating and capital costs as at December 31, 2016. All financial information presented in this press release are based on estimates and are unaudited.

In 2016 Touchstone remained sensitive to the low commodity price environment and continued to follow a strategy of conservatively deploying exploration and development capital. The Company focused on operations directly related to maintaining production from the Company's core assets and arresting base declines through low cost recompletion projects. Touchstone recompleted a total of nine wells and stimulated two wells as part of an evaluation project but deployed no drilling capital during the fiscal year. Notwithstanding the Company's minimal capital investment in 2016, annual crude oil production was 476,057 barrels, representing an average of 1,301 barrels per day. The Company was able to organically grow reserves as a result of better than previously forecasted well performance and the effectiveness of the recompletion program.

2016 Reserve Report Highlights

	•	Proved developed producing reserves ("PDP"):
		-	Decreased 6% to 4,606 Mbbl, replacing 40% of 2016 production.
		-	Reserve life index of 9.9 years based on forecast 2017 PDP production of 1,277 bbls/d.
		-	PDP comprise 51% of 1P and 29% of 2P.
	•	Proved reserves ("1P"):
		-	Increased 2% to 8,977 Mbbl, replacing 134% of 2016 production.
		-	Reserve life index of 15.1 years based on forecast 2017 1P production of 1,628 bbls/d.
		-	1P comprise 57% of 2P.
	•	Proved plus probable reserves ("2P"):
		-	Increased 2% to 15,698 Mbbl, replacing 149% of 2016 production.
		-	Reserve life index of 24.0 years based on forecast 2017 2P production of 1,790 bbls/d.
	•	Total 2P net present value of future net revenues before tax (10 percent discount rate) of $324.9 million ($161.1 million on a 1P basis).
	•	Total 2P net present value of future net revenues after tax (10 percent discount rate) of $130.7 million, which excluding net debt equated to a net asset value of $1.57 per basic common share ($72.7 million or $0.87 per basic common share on a 1P basis).
	•	Total future development costs ("FDC") of $48.7 million for 1P and $72.3 million for 2P.
	•	Finding and development costs (including changes in FDC) were $7.35 for 1P and $6.00 for 2P. Using the Company's estimated operating netback before hedging of $15.08 per barrel, the 1P recycle ratio was 2.05 times and the 2P recycle ratio was 2.51 times.

Future development costs are associated with a portion of the Company's internally identified drilling location inventory and the Company's estimated portfolio of low cost, low risk recompletion projects.

	•	1P have been assigned for 52 drilling locations (25% of the Company's identified drilling inventory) and 64 recompletions (19% of the Company's identified recompletion projects).
	•	2P have been assigned to 78 drilling locations (38% of the Company's identified drilling inventory) and 122 recompletions (36% of the Company's identified recompletion projects).

The Company's total inventory of 208 drilling locations and 338 recompletion or workover projects are based upon current Management estimates. The Company currently operates 1,133 wells in Trinidad, 410 of which had associated production in 2016.

GLJ has forecast reserve volumes and future cash flows based upon current and historical well performance through to the economic production limit of individual wells. Notwithstanding established precedence and contractual options for the continuation and renewal of the Company's existing operating agreements, in many cases the forecast economic limit of individual wells are beyond the current term of the relevant operating agreements.

2016 Year-end Reserves Summary

The tables below disclose the following in relation to the Company's development properties, which as of December 31, 2016 are all located onshore within Trinidad. The figures in the following tables have been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in NI 51-101. In certain tables set forth below, the columns may not add due to rounding. All dollar amounts are reported in thousands of Canadian dollars unless otherwise indicated.

December 31, 2016 Gross Reserves^(1),(2)

		Light and Medium Oil (Mbbl)	Heavy Oil (Mbbl)	Total Oil Equivalent (Mbbl)
Proved
	Proved producing	3,955	651	4,606
	Proved non-producing	735	213	948
	Proved undeveloped	2,890	533	3,423
Total proved		7,580	1,397	8,977
Probable		5,914	808	6,722
Total proved plus probable		13,494	2,205	15,698
(1) Gross Reserves are the Company's working interest share of the remaining reserves before deduction of any royalties.
(2) See "Advisories: Oil and Natural Gas Reserves".

Reconciliation of Changes in Gross Reserves^(1),(2)

		Proved (Mbbl)	Proved Plus Probable(Mbbl)
December 31, 2015		8,815	15,465
	Extensions and improved recovery	481	466
	Technical revisions	190	276
	Economic factors	(33)	(33)
	Production	(476)	(476)
December 31, 2016		8,977	15,698
Reserves replacement ratio (%)(3)		134	149
(1) Gross Reserves are the Company's working interest share of the remaining reserves before deduction of any royalties.
(2) See "Advisories: Oil and Natural Gas Reserves".
(3) Reserves replacement ratio is calculated as increase to reserves divided by 2016 average production of 476 Mbbl. See "Advisories - Oil and Gas Metrics".

Net Present Values of Future Net Revenue as of December 31, 2016^(1),(2)

		Net Present Values of Future Net Revenues Before Income Taxes Discounted at (% per year) ($000's)
		0%	5%	10%	15%	20%
Proved
	Proved producing	135,098	83,260	62,240	50,732	43,305
	Proved non-producing	49,825	41,109	34,654	29,732	25,887
	Proved undeveloped	112,953	83,755	64,199	50,503	40,562
Total proved		297,876	208,125	161,093	130,967	109,753
Probable		327,003	220,407	163,770	128,052	103,516
Total proved plus probable		624,878	428,551	324,863	259,018	213,269

		Net Present Values of Future Net Revenues After Income Taxes(3)Discounted at (% per year) ($000's)
		0%	5%	10%	15%	20%
Proved
	Proved producing	65,425	46,613	38,095	32,990	29,449
	Proved non-producing	18,099	15,447	13,486	11,982	10,795
	Proved undeveloped	39,408	28,407	21,088	15,985	12,301
Total proved		122,931	90,466	72,668	60,958	52,546
Probable		114,765	77,910	58,072	45,426	36,686
Total proved plus probable		237,696	168,376	130,740	106,383	89,233
(1) Based on GLJ's December 31, 2016 escalated price forecast. See "Pricing and Foreign Exchange Assumptions".
(2) See "Advisories: Oil and Natural Gas Reserves".
(3) Income taxes include all resource income, appropriate income tax calculations per current Trinidad tax regulations and estimated December 31, 2016 tax pools and non-capital losses.

Pricing and Foreign Exchange Assumptions

The following table sets forth the benchmark reference prices reflected in the Reserves Report. This price forecast was GLJ's standard price forecast effective January 1, 2017.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS AS OF JANUARY 1, 2017(1)
Forecast Year	Inflation Rate (%/year)	US$/Cdn$ Exchange Rate	WTI Cushing Oklahoma (US$/bbl)	Brent Blend Crude Oil FOB North Sea (US$/bbl)	Edmonton Par Price 40 API Light Sweet Crude Oil (Cdn$/bbl)
2017	2.0	0.750	55.00	57.00	69.33
2018	2.0	0.775	59.00	61.00	72.26
2019	2.0	0.800	64.00	66.00	75.00
2020	2.0	0.825	67.00	70.00	76.36
2021	2.0	0.850	71.00	74.00	78.82
2022	2.0	0.850	74.00	77.00	82.35
2023	2.0	0.850	77.00	80.00	85.88
2024	2.0	0.850	80.00	83.00	89.41
2025	2.0	0.850	83.00	86.00	92.94
2026	2.0	0.850	86.05	89.64	95.61
Thereafter	2.0	0.850	+2.0%/year	+2.0%/year	+2.0%/year
(1) This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer. Product sales prices will reflect these reference prices with further adjustments for quality differentials and transportation to point of sale.

Future Development Costs

The following table provides information regarding the development costs deducted in the estimation of the Company's future net revenue using forecast prices and costs as included in the Reserves Report.

Year Incurred	For Proved Reserves ($000's)	For Proved Plus Probable Reserves ($000's)
2017	5,980	5,980
2018	13,617	19,181
2019	21,897	33,742
2020	7,206	13,398
Thereafter	-	-
Total undiscounted	48,700	72,301
Total discounted at 10% per year	39,921	58,513

Estimated Finding and Development Costs Including FDC

	For Proved Reserves	For Proved Plus Probable Reserves
Exploration capital expenditures (000's)(1),(2)	1,823	1,823
Development capital expenditures (000's)(1),(2)	842	842
Change in future development costs ($000's)	2,022	1,592
Estimated Finding and development costs ($000's)(3)	4,687	4,257
Net reserve additions (Mbbl)(3)	638	709
Estimated finding and development costs per barrel ($/bbl)(3)	7.35	6.00
(1) Financial information is based on the Company's preliminary 2016 unaudited financial statements and is therefore subject to audit. Accordingly, unaudited capital expenditure amounts used in the calculation of finding and development costs are management's estimate and are subject to change.
(2) Exploration and development capital excludes capitalized general and administration costs. See "Advisories - Oil and Gas Metrics".
(3) See "Advisories: Oil and Natural Gas Reserves" and "Advisories - Oil and Gas Metrics".

Advisories

Oil and Natural Gas Reserves: The disclosure in this press release summarizes certain information contained in the Reserves Report but represents only a portion of the disclosure required under NI 51-101. Full disclosure with respect to the Company's reserves as at December 31, 2016 will be contained in the Company's Annual Information Form for the year ended December 31, 2016 which will be filed on SEDAR on or before March 31, 2017. All evaluations and reviews of future net revenues are stated prior to any provision for finance expenses or general and administrative costs and after the deduction of estimated future capital expenditures and estimated future well abandonment costs. It should not be assumed that the present worth of estimated future net revenues presented in the tables above represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of crude oil provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may be greater than or less than the estimates provided herein.

Oil and Gas Metrics: This press release contains certain oil and gas metrics that are commonly used in the oil and gas industry such as finding and development costs, reserves additions, reserves replacement ratio, reserve life index, net asset value and recycle ratio. These metrics do not have standardized meanings or standardized methods of calculation and therefore such measures may not be comparable to similar measures presented by other companies. Such metrics have been included herein to provide readers with additional metrics to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company, and future performance may not compare to the performance in prior periods and therefore such metrics should not be unduly relied upon. The Company uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment purposes.

Finding and development costs are the sum of capital expenditures excluding capitalized general and administrative costs incurred in the period and the change in future development costs required to develop those reserves. The Company's annual audit of its December 31, 2016 consolidated financial statements is not complete. Accordingly, unaudited capital expenditure amounts used in the calculation of finding and development costs are management's estimate and are subject to change. Finding and development costs per barrel is determined by dividing current period net reserve additions to the corresponding period's finding and development cost. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Reserve additions are calculated as the change in reserves from the beginning to the end of the applicable period excluding period production.

Reserves replacement ratio is calculated as period reserve additions divided by period production.

Reserve life index is calculated as total Company net reserves divided by annual production.

The Company calculates net asset value per share by dividing the net present value of the Company's applicable reserves category discounted at 10% as presented in the Reserves Report by the weighted average number of common shares outstanding during the applicable period.

Recycle ratios are calculated by dividing the current period finding and development costs per barrel to operating netbacks before hedging in the corresponding period (see "Non-GAAP Measures"). The recycle ratio compares netbacks from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement of reserves are of equivalent quality as the produced reserves.

Drilling and recompletion locations: This press release discloses drilling and recompletion locations in three categories: (i)1P locations; (ii) 2P locations; and (iii) unbooked locations.1P locations and 2P locations are derived from the Reserves Report and account for locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the prospective acreage associated with the Company's assets and an assumption as to the number of wells that can be drilled/recompleted based on industry practice and internal review. Unbooked locations do not have attributed reserves. Of the approximately 208 (net) drilling locations identified herein, 52 are 1P locations, 26 are 2P locations and the remaining are unbooked locations. Of the approximately 338 (net) recompletion locations identified herein, 64 are 1P locations, 58 are 2P locations and the remaining are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling/recompletion activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill/recomplete all unbooked locations and if drilled/recompleted there is no certainty that such locations will result in additional oil and gas reserves or production. The locations on which the Company will actually drill/recomplete wells will ultimately depend upon the availability of capital, regulatory approvals, crude oil prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where Management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production.

Non-GAAP Measures: The Company uses operating netback as a key performance indicator of field results. Operating netback does not have a standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures by other companies. Operating netback is presented on a per barrel basis and is calculated by deducting royalties and operating expenses from petroleum revenue. Operating netback is presented herein prior to realized gains or losses on derivative contracts. The Company's annual audit of its December 31, 2016 consolidated financial statements is not complete. Accordingly, unaudited figures used in the calculation of operating netback and recycle ratios are management's estimate and are subject to change. The Company considers operating netbacks to be a key measure as they demonstrate Touchstone's profitability relative to current commodity prices. This measurement assists Management and investors in evaluating operating results on a per barrel basis to analyze performance on a historical basis.

Forward-Looking Statements: Certain information provided in this press release may constitute forward-looking statements within the meaning of applicable securities laws. Forward-looking information in this press release may include, but is not limited to, statements about the Company's forward strategy, timing and levels of capital expenditures, future production levels, drilling and recompletion location inventory, future development costs associated with oil and gas reserves, sufficiency of resources to fund operations and plans related to and the timing of certain projects. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Because forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. Certain of these risks are set out in more detail in the Company's Annual Information Form dated March 24, 2016 which has been filed on SEDAR and can be accessed at www.sedar.com. The forward-looking statements contained in this press release are made as of the date hereof; and except as may be required by applicable securities laws, the Company assumes no obligation to update publicly or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Crude Oil Abbreviations

bbls	barrels of oil
Mbbl	thousand barrels of oil
bbls/d	barrels of oil per day

About Touchstone

Touchstone Exploration Inc. is a Calgary based company engaged in the business of acquiring interests in petroleum and natural gas rights, and the exploration, development, production and sale of petroleum and natural gas. Touchstone is currently active in onshore properties located in the Republic of Trinidad and Tobago. The Company's common shares are traded on the Toronto Stock Exchange under the symbol "TXP".