PetroShale Announces 2018 Financial and Operating Results Highlighted by Significant Reserves Increase

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Apr 10, 2019, 07:00 ET

CALGARY, April 10, 2019 /CNW/ - PetroShale Inc. ("PetroShale" or the "Company") (TSXV: PSH, OTCQX: PSHIF) is pleased to announce our financial and operating results for the three and twelve month periods ended December 31, 2018 and significant increases across all reserves categories as of December 31, 2018.

The Company's audited consolidated financial statements and corresponding Management's Discussion and Analysis (MD&A) for the period will be available on SEDAR at www.sedar.com, on the OTCQX website at www.otcqx.com, and on PetroShale's website at www.petroshaleinc.com. Copies of the materials can also be obtained upon request without charge by contacting the Company directly. Please note, currency figures presented herein are reflected in Canadian dollars, unless otherwise noted.

2018 FINANCIAL & OPERATING HIGHLIGHTS

Production averaged 6,014 barrels of oil equivalent per day ("boepd") (84% liquids) in the fourth quarter of 2018, which is 184% higher than the same period in 2017, while production averaged 5,630 boepd (87% liquids) in calendar 2018, an increase of 130% over 2017.
On a fully diluted per share basis, fourth quarter and calendar 2018 production grew by 129% and 63%, respectively year over year.
Revenue increased to $26.2 million in the fourth quarter of 2018 and $121.8 million in calendar 2018, driven by higher production and realized prices.
Adjusted EBITDA increased to $11.7 million in the fourth quarter, 109% higher than the same period in 2017 reflecting a significant increase in production in the latter part of the year and offsetting weaker Bakken oil prices. For calendar 2018, adjusted EBITDA was $64.9 million, an increase of 207% over 2017.
Adjusted EBITDA per fully diluted share was $0.06 in the fourth quarter of 2018, a 68% increase over the fourth quarter of 2017. For calendar 2018 adjusted EBITDA per fully diluted share was $0.37, a 117% increase over calendar 2017.
Net income increased to $8.0 million in the fourth quarter of 2018 and to $27.1 million for calendar 2018 compared to net losses of $1.5 and $3.1 million in the respective prior periods of 2017. Net income per fully diluted share increased to $0.16 for 2018 from a loss of $0.03 in 2017.
Operating netback, prior to the impact of hedging, increased by 35% to $37.07 per boe for calendar 2018.
Capital expenditures totaled $195.2 million for the year with approximately $93.5 million (48%) directed towards acquisitions and $101.7 million (52%) for drilling, completions and construction activities.
Over 2018, added 18.8 net locations (proved plus probable) as a result of acquisitions completed during the year.
The borrowing base under our senior credit facility increased to US$125 million in November.

2018 RESERVES HIGHLIGHTS

PetroShale significantly increased our oil and natural gas reserves and the estimated net present value of future net revenue (discounted at 10% -"NPV10") across all reserve categories at year end 2018 compared to December 31, 2017:

Proved developed producing ("PDP") reserves grew 122% to 12.3 million boe ("MMboe"), total proved ("TP") reserves increased 61% to 49.2 MMboe, and total proved plus probable ("P+P") reserves increased 71% to 62.8 MMboe.
NPV10 increased meaningfully across all categories, rising 125% for PDP to $208.4 million, 53% for TP to US$655.0 million and 73% for P+P reserves to US$850.6 million, attributable to the Company's 2018 development program and acquisitions.

On a fully diluted per share basis, TP reserves grew from $4.35 to $5.11 year over year and P+P reserves grew from $5.02 to $6.63.
Net asset value per basic share increased to $5.14 based on the NPV10 of the P+P reserves after adjusting for total debt of $181.9 million with $11.1 million assumed for undeveloped land.
PetroShale realized attractive capital efficiencies through the execution of our 2018 development program, which resulted in TP and P+P finding and development ("F&D") costs (including change in future development capital¹ or "FDC") of $22.61 per boe and $7.82 per boe, respectively. The Company generated finding, development and acquisition ("FD&A") costs of $17.86 per boe and $12.94 per boe, respectively on TP and P+P reserves.
PetroShale generated TP F&D and FD&A recycle ratios of 1.6 and 2.1 times, respectively, and P+P F&D and FD&A recycle ratios of 4.7 and 2.9 times, respectively, based on our operating netback prior to hedging of $37.07 per boe.
The three-year average P+P FD&A and F&D costs were $13.44 per boe and $12.85 per boe, resulting in a recycle ratio of 2.8 and 2.9 times, respectively.
Our P+P Reserve Life Index ("RLI") totaled 29 years based on annualized fourth quarter 2018 average production of 6,014 boepd.

_______________________________

¹ Converted to Canadian dollars using the average 2018 exchange rate of US$1.00 = Cdn$1.30.

FINANCIAL & OPERATING REVIEW

			Three months ended				Twelve months ended
FINANCIAL (in thousands, except per share & share data)				December 31, 2018	December 31, 2017		December 31, 2018		December 31, 2017
Oil and natural gas revenue		$		26,231	$	10,323	$	121,797	$	43,262
Net income (loss)				7,982	(1,482)		27,056		(3,093)
	Per share - diluted			0.04	(0.02)		0.16		(0.03)
Adjusted EBITDA⁽¹⁾				11,684	5,600		64,937		21,135
Capital expenditures				27,606	34,531		195,212		67,109
Net debt⁽¹⁾							176,978		90,126
Common shares outstanding
	Weighted average – basic			191,040,112	157,127,767		170,866,944		123,279,448
	Weighted average – diluted			194,482,248	157,127,767		174,391,337		123,279,448


				Three months ended			Twelve months ended
OPERATING		December 31, 2018			December 31, 2017		December 31, 2018		December 31, 2017
Sales volumes
	Crude Oil (Bbl/d)			4,185	1,554			4,134	1,878
	Natural gas (Mcf/d)			5,765	1,802			4,520	1,770
	NGLs (Bbl/d)			868	266			743	272
	Barrels of oil equivalent (Boe/d)⁽²⁾			6,014	2,121			5,630	2,445

Average realized prices
	Crude Oil ($/Bbl)	$		64.89	$	68.38	$	77.53	$	60.28
	Natural gas ($/Mcf)			1.24	1.88			1.17	1.79
	NGLs ($/Bbl)			7.39	9.93			10.64	7.89
	Barrels of oil equivalent ($/Boe)	$		47.41	$	52.96	$	59.27	$	48.48

Operating netback ($/Boe)^{(1) (2)}
	Revenue	$		47.41	$	52.96	$	59.27	$	48.48
	Royalties			(9.64)	(11.03)			(11.73)	(10.19)
	Realized loss on derivatives			(1.67)	-			(3.10)	-
	Operating costs			(6.85)	(5.94)			(4.55)	(6.15)
	Production taxes			(3.67)	(3.97)			(4.57)	(3.65)
	Transportation expense			(1.68)	(0.80)			(1.35)	(1.03)
	Operating netback⁽¹⁾	$		23.90	$	31.22	$	33.97	$	27.46
	Operating netback prior to hedging⁽¹⁾	$		25.57	$	31.22	$	37.07	$	27.46

⁽¹⁾	See "Non-IFRS measures".
⁽²⁾	See "Oil and Gas Advisories".

2018 YEAR-END RESERVES

The reserves data in this press release is based upon an evaluation by Netherland, Sewell & Associates, Inc. ("NSAI") with an effective date of December 31, 2018. The reserves data summarizes PetroShale's crude oil and natural gas reserves and the net present value of future net revenue for these reserves using forecast prices and costs. All references to reserves are to gross Company reserves, meaning PetroShale's working interest reserves before consideration of royalty interests. The reserve report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in National Instrument 51‑101 ("NI 51-101") and CSA Staff Notice 51‑324. No attempt was made to evaluate possible reserves.

Gross and Net Company Interest Reserves

		Reserves
		Tight Oil		Shale Gas⁽²⁾		Natural Gas Liquids ⁽²⁾		BOE
		Gross	Net	Gross	Net	Gross	Net	Gross	Net
Reserves Category		(Mbbl)	(Mbbl)	(Mmcf)	(Mmcf)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)
PROVED:
	Developed Producing	8,757.3	7,133.6	11,701.3	9,558.6	1,556.6	1,247.8	12,264.1	9,974.5
	Developed Non-Producing	-	-	-	-	-	-	-	-
	Undeveloped	28,715.8	23,618.5	25,961.3	21,397.0	3,875.0	3,128.5	36,917.7	30,313.2
TOTAL PROVED		37,473.1	30,752.1	37,662.6	30,955.5	5,431.6	4,376.3	49,181.8	40,287.7
PROBABLE		10,407.2	8,420.8	10,301.6	8,367.1	1,490.5	1,191.3	13,614.6	11,006.6
TOTAL PROVED PLUS PROBABLE		47,880.3	39,172.9	47,964.3	39,322.7	6,922.1	5,567.6	62,796.5	51,294.3

Notes:
(1)	Columns may not add due to rounding.
(2)	All of our shale gas reserves and natural gas liquids are produced in solution with our tight oil. The natural gas liquid reserves are recovered from our natural gas reserves downstream of the wellhead.

Net Present Value of Future Net Revenue

		Before Income Taxes Discounted at (%/year)
		0%	5%	10%	15%	20%
Reserves Category		($US 000s)	($US 000s)	($US 000s)	($US 000s)	($US 000s)
PROVED:
	Developed Producing	360,580.9	263,316.2	208,352.3	173,847.8	150,378.8
	Developed Non-Producing	-	-	-	-	-
	Undeveloped	1,045,930.3	652,037.4	446,642.2	324,574.1	245,064.3
TOTAL PROVED		1,406,511.2	915,353.6	654,994.5	498,421.8	395,443.2
PROBABLE		469,547.3	285,215.4	195,621.9	144,834.9	112,792.6
TOTAL PROVED PLUS PROBABLE		1,876,058.4	1,200,569.0	850,616.4	643,256.7	508,235.8

Note:
(1)	Columns may not add due to rounding.

As a reporting issuer in Canada, PetroShale is required to report our reserves and NPV10 using forecast pricing and costs, as stipulated under NI 51-101. The forecast prices reflected in the NPV10 is included in our 2018 Annual Information Form, expected to be filed on SEDAR before the end of April, 2019.

Reserves Reconciliation

		Total (Mboe)
		Total Proved	Probable	Total Proved Plus Probable
December 31, 2017		30,602.5	6,134.6	36,737.0
	Discoveries	-	-	-
	Extensions and Improved Recovery	-	-	-
	Product Type Transfers⁽¹⁾	2,613.0	415.6	3,028.6
	Technical Revisions⁽²⁾	313.3	4,438.4	4,751.7
	Acquisitions⁽³⁾	17,769.3	2,636.4	20,405.8
	Dispositions	-	-	-
	Economic Factors	(61.6)	(10.4)	(72.0)
	Production	(2,054.7)	-	(2,054.7)
December 31, 2018⁽⁴⁾		49,181.9	13,614.6	62,796.5

Notes:
(1)	Product type transfers reflects the initial inclusion of NGLs in the Company's reserves beginning on January 1st, 2018, and the offsetting adjustment to wellhead gas as a result of NGL recovery.
(2)	Technical revisions include removal of locations based on development permitting and activity of our operators on non-operated properties and probable reserve assignments to proved well locations. Additionally, it reflects changes to reserves based on estimates from further production information gathered in 2018 from our wells and analogous wells near our lands, and revisions to interest on certain non-operated wells.
(3)	The acquisitions amount is the estimate of reserves at December 31, 2018, adjusted for production associated with the acquired properties from the related acquisition date to December 31, 2018.
(4)	Columns may not add due to rounding.

2018 Capital Program Efficiency

		Finding, Development & Acquisition ("FD&A")⁽¹⁾		Finding & Development ("F&D")⁽¹⁾
		Total Proved	Proved plus Probable	Total Proved	Proved plus Probable
Capital Costs ($000s)
	Acquisitions	93,520	93,520	-	-
	Capital expenditures	101,692	101,692	101,692	101,692
	Change in future development capital	173,406	168,477	(36,498)	(41,428)
Total FD&A / F&D Costs		368,618	363,689	65,194	60,264

Reserves additions (Mboe)
	Net change in reserve volumes	18,579	26,059	18,579	26,059
	Add back production	2,055	2,055	2,055	2,055
	Reserves associated with acquisitions	-	-	(17,769)	(20,406)
Total additions		20,634	28,114	2,865	7,708
FD&A and F&D Costs ($/boe)		$17.86	$12.94	$22.76	$7.82
Three Year FD&A and F&D Costs ($/boe)⁽²⁾		$16.97	$13.44	$22.61	$12.85
Recycle Ratio⁽³⁾		2.1	2.9	1.6	4.7
Three Year Recycle Ratio⁽⁴⁾		2.2	2.8	1.6	2.9

Notes:
(1)	The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and probable reserves into production. The FDC was converted to Canadian dollars using the average 2018 exchange rate of US$1.00 = Cdn$1.30. In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures, after changes in FDC, by the applicable reserves additions. We have disclosed both finding and development costs and finding, development and acquisition costs because acquisition costs have been a significant component of our total capital expenditures and strategy, and also due to the difficulty in allocating changes in future development costs between reserve additions from drilling, technical revisions and acquisitions. For purposes of calculating finding and development costs, we have chosen to reflect the change in future development costs associated with drilling activity during the year and exclude the increase in future development costs associated with acquisitions.
(2)	The calculation of the three year FD&A and F&D costs reflect the sum of the capital costs and net reserve additions for the years 2016 through 2018.
(3)	Recycle ratio is defined as operating netback for 2018, divided by F&D or FD&A costs, as applicable, on a per boe basis. Operating netback is calculated as revenue (excluding realized hedging gains and losses) minus royalties, operating costs, production taxes and transportation expense. PetroShale's operating netback (prior to hedging) in 2018 averaged $37.07 per boe.
(4)	The calculation of the three year recycle ratio reflects the operating netback (prior to hedging) for calendar year 2018, divided by the three year F&D or FD&A costs, as applicable, on a per boe basis.

Net Asset Value ("NAV") per Share as at December 31, 2018
($ thousands, except share and per share amounts)

	Proved Plus Probable Reserve Value (NPV10 Before Tax)					$ 1,156,838
	Undeveloped Land Value					11,098
	Net Debt (including Decommissioning Obligation)⁽¹⁾					(181,912)
	Total Net Assets					$ 986,023
	Common Shares Outstanding					191,758,236
	Estimated Net Asset Value per Basic Common Share⁽²⁾					$ 5.14
	Estimated Net Asset Value per Diluted Common Share					$5.04
	Estimated Net Asset Value per Diluted Common Share (assuming exchange of Preferred Shares)					$4.20

Notes:
(1)	See "Non-IFRS Measures".
(2)	Net asset value is calculated as at a particular date and is, by its nature, historical, and may not be reflective of PetroShale's future performance. The NAV reflects the NPV10 of the Company's reserves at an exchange rate of US$1.00 = Cdn$1.36, which was the market rate at December 31, 2018.

MESSAGE FROM THE CEO

PetroShale recorded another very active year with ongoing operated and non-operated development activity and strategic acquisitions of high-quality assets in the heart of the North Dakota Bakken/ Three Forks play. As a result of these efforts, the Company achieved significant growth in reserves on both an absolute and per share basis, generated significantly higher adjusted EBITDA and increased average annual production by 130% over 2017.

Early in 2018, PetroShale completed a strategic financing with a private equity investor based in the U.S. with proceeds used to retire the Company's previous subordinated loan facility via the issuing of US$75 million of preferred shares having a five year term and 9% coupon. We further enhanced our financial flexibility through 2018 by increasing the borrowing capacity of our senior credit facility to US$125 million, which currently affords PetroShale substantial undrawn credit capacity of US$57 million to carry out our ongoing drilling and completion programs and to pursue further accretive and strategic acquisitions. In addition to our robust liquidity, the balance sheet remains strong with senior debt at 1.1 times adjusted EBITDA at December 31, 2018.

During the year, we invested $101.7 million in drilling, completions and construction expenditures for the drilling of 37 gross (6.4 net) wells and the completion of 31 gross (7.88 net) wells. Major operated drilling activity included the drilling of seven (6.1 net) wells in our Horse Camp West, Primus East and Bear Chase units. Major operated completion activity included completing six gross (5.5 net) wells in our Primus West, Horse Camp West and Horse Camp East units. Major non-operated activity included participating in the drilling of three (0.8 net) wells at the Jore unit and completion of four (1.6 net) wells at the Packineau unit.

In 2018, we closed a strategic acquisition of assets within our North Dakota Bakken core area which included approximately 550 boepd of low decline production (~90% light oil and liquids), as well as significant working interests in three primarily undeveloped drilling units that will be operated by PetroShale (the "Acquisition"). The Acquisition added 14.3 net locations (proved plus probable) to our inventory of low-risk infill drilling locations. Concurrent with the Acquisition, we closed a bought deal public equity financing and private placement financing (the "Equity Financings"), raising aggregate gross proceeds of $58.5 million. Net proceeds from the Equity Financings, along with a US$10.5 million draw on PetroShale's senior credit facility, were used to fund the Acquisition.

WTI benchmark and Bakken differential prices remained strong through most of 2018, averaging approximately US$64.76 and US$5.12 per Bbl, respectively. Higher oil prices and net production volumes during the first nine months of 2018 led to higher Company revenue, cash flow from operations and adjusted EBITDA relative to the same period in 2017. However, during the fourth quarter WTI oil prices decreased to an average of US$58.70 per Bbl. In addition, the average Bakken oil price differential to WTI widened significantly to US$9.61 per Bbl due to refinery maintenance and a surplus of Canadian oil supply, all of which negatively impacted our operating netback in Q4 2018, which averaged $23.90 per Boe ($25.57 per Boe prior to hedging). As anticipated, the Bakken differential narrowed in the first few months of 2019 following a return of refinery capacity and stabilization of Canadian oil supply as a result of Alberta production cuts.

OUTLOOK

The Company remains active in 2019, executing a continuous development program with one operated rig and participating in various non-operated wells. During the first quarter of 2019 we drilled two gross (1.0 net) wells in our Helen unit and are currently drilling four (2.2 net) wells at our Thunder Cloud unit. We are in the process of completing two (1.4 net) wells at our Primus East unit where we will commission facilities later in the second quarter. Also in the second quarter we plan to frac three gross (2.8 net) wells in our Bear Chase unit that we plan to bring on line in the third quarter of 2019.

Our production in the first half of 2019 has been impacted by one-time events as we shut-in certain wells to protect them from nearby fracing activities and/or to install artificial lift. These events, as well as natural declines, will lead to average production in the first half of 2019 between 5,000 to 6,000 boepd. We expect significantly higher average production in the second half of 2019 of 10,000 to 11,000 boepd with an estimated 2019 exit rate of approximately 11,000 boepd.

PetroShale had a strong 2018 with substantial growth in production, EBITDA and reserves. Going forward, we are well positioned in 2019 to continue executing our oil-focused, Bakken strategy with plans to continue increasing production with the drilling of approximately 20 gross (9.0 net) wells, of which 6.8 net wells will be operated.

As always, we wish to thank all of PetroShale's employees, directors and shareholders for your continued support and look forward to updating you on our progress and achievements in the future.

((signed))

Mike Wood
President & CEO

About PetroShale

PetroShale is an oil company engaged in the acquisition, development and production of top-tier oil-weighted assets in the North Dakota Bakken / Three Forks.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

Note Regarding Forward-Looking Statements and Other Advisories

This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to, among other things, available aspects of management focus, objectives, strategies and business opportunities. More particularly and without limitation, this press release contains forward-looking information concerning: the Company's plans to participate in various non-operated wells throughout the year, to frac three gross (2.8 net) wells in our Bear Chase unit, plans to continue increasing production with the drilling of approximately 20 gross (9.0 net) wells, of which 6.8 net wells are expected to be operated, that the Company will have the availabilities under its credit facility (or otherwise) to pursue the opportunities discussed herein, the Company's expected production rates in 2019 and the general outlook of the Company. PetroShale provided such forward-looking statements in reliance on certain expectations and assumptions that it believes are reasonable at the time, including expectations and assumptions concerning prevailing commodity prices, liquidity, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; plant turnaround times and continued rail service to transport products; reserve volumes; business prospects and opportunities; the availability and cost of financing, labor and services; the impact of increasing competition; ability to market oil and natural gas successfully; and the Company's ability to access capital (including its senior credit facility).

Statements relating to "reserves" are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

Although the Company believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because the Company can give no assurance that they will prove to be correct. Forward-looking information addresses future events and conditions, which by their very nature involve inherent risks and uncertainties. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits the Company will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on the Company's future operations and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). These forward-looking statements are made as of the date of this press release and the Company disclaims any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

All references herein to fully diluted share basis is based upon the weighted average number of fully diluted shares as disclosed in the Company's Management & Discussion Analysis as at December 31, 2018 and for the three months and years ended December 31, 2018 and 2017 – "Financial and Operational Highlights".

Non-IFRS Measures:

Within this press release, references are made to "operating netback", "operating netback prior to hedging", "net debt" and "adjusted EBITDA", which are not recognized measures under IFRS and therefore may not be comparable to performance measures presented by others. Adjusted EBITDA represents cash flow from operating activities prior to changes in non-cash working capital. Operating netback represents revenue, plus or minus any realized gain or loss on financial derivatives, less royalties, production taxes, operating costs and transportation expense, with the net amount divided by the working interest production volumes to derive the operating netback on a per Boe basis. Operating netback prior to hedging represents operating netback prior to any realized gain or loss on financial derivatives. Net debt represents total liabilities, excluding any decommissioning obligation and financial derivative liability, less current assets. The Company believes that adjusted EBITDA provides useful information to the reader in that it measures the Company's ability to generate funds to service its debt and other obligations and to fund its operations, without the impact of changes in non-cash working capital which can vary based solely on timing of settlement of accounts receivable and accounts payable. Management believes that in addition to net income (loss) and cash flow from operating activities, operating netback and adjusted EBITDA are useful supplemental measures as they assist in the determination of the Company's operating performance, leverage and liquidity. Operating netback is commonly used by investors to assess performance of oil and gas properties and the possible impact of future commodity price changes on energy producers. Readers are cautioned, however, that these measures should not be construed as an alternative to net income (loss) or cash flow from (used in) operating activities as determined in accordance with IFRS as an indication of our performance or value.

Oil and Gas Advisories:

Where amounts are expressed on a barrel of oil equivalent ("Boe") basis, natural gas volumes have been converted to Boe using a ratio of 6,000 cubic feet of natural gas to one barrel of oil (6 Mcf: 1 Bbl). This Boe conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 Bbl, utilizing a conversion ratio at 6 Mcf: 1 Bbl may be misleading as an indication of value. In this release, mboe refers to thousands of barrels of oil equivalent, while mbbls refers to thousands of barrels of oil, and mmcf refers to millions of cubic feet of natural gas.

This news release contains metrics commonly used in the oil and natural gas industry, such as "recycle ratio", "operating netback", "finding and development" ("F&D") costs and "finding, development and acquisition ("FD&A") costs". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Details of how these measures have been calculated are included in the body of this press release and, in respect of "operating netback", under the heading "Non-IFRS Measures". "Reserve life index ("RLI")" is calculated as by dividing the quantity of reserves by the average production from those reserves for the fourth quarter of 2018.

Drilling Locations

This press release discloses drilling locations as proved and probable locations. Proved plus probable drilling locations set forth herein are based on the Company's most recent independent reserves evaluation as prepared by Netherland, Sewell & Associates Inc. as of December 31, 2018. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.

All dollar figures included herein are presented in Canadian dollars, unless otherwise noted.

SOURCE PetroShale Inc.

PetroShale Inc., Attention: President and CEO, Email: [email protected], Phone: +1.303.297.1407, www.petroshaleinc.com or Cindy Gray, 5 Quarters Investor Relations, Inc., 403.828.0146 or [email protected]

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